Edgar Filing: DOMINION RESOURCES INC /VA/

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2009

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 001-08489

LOGO

DOMINION RESOURCES, INC.

(Exact name of registrant as specified in its charter)


VIRGINIA		54-1229715
*(State or other jurisdiction of* *incorporation or organization)*		*(I.R.S. Employer* *Identification No.)*

120 TREDEGAR STREET RICHMOND, VIRGINIA		23219
*(Address of principal executive offices)*		*(Zip Code)*

(804) 819-2000

(Registrant’s telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes ¨ No x

At June 30, 2009, the latest practicable date for determination, 595,252,378 shares of common stock, without par value, of the registrant were outstanding.

DOMINION RESOURCES, INC.

INDEX


		Page Number
	Glossary of Terms	3

	PART I. Financial Information

Item 1.	Consolidated Financial Statements

	Consolidated Statements of Income – Three and Six Months Ended June 30, 2009 and 2008	4

	Consolidated Balance Sheets – June 30, 2009 and December 31, 2008	5

	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2009 and 2008	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46

Item 4.	Controls and Procedures	47

	PART II. Other Information

Item 1.	Legal Proceedings	48

Item 1A.	Risk Factors	48

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49

Item 4.	Submission of Matters to a Vote of Security Holders	50

Item 6.	Exhibits	51

PAGE 2

GLOSSARY OF TERMS

The following abbreviations or acronyms used in this Form 10-Q are defined below:


Abbreviation or Acronym		Definition
AOCI		Accumulated other comprehensive income (loss)
AROs		Asset retirement obligations
bcf		Billion cubic feet
bcfe		Billion cubic feet equivalent
CEO		Chief Executive Officer
CFO		Chief Financial Officer
DCI		Dominion Capital, Inc.
DD&A		Depreciation, depletion and amortization expense
Dominion		The legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries or operating segments, or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries
DEI		Dominion Energy, Inc.
Dominion Direct^®		A dividend reinvestment and open enrollment direct stock purchase plan
Dominion East Ohio		The East Ohio Gas Company
DVP		Dominion Virginia Power operating segment
E&P		Exploration and production
EITF		Emerging Issues Task Force
EPA		Environmental Protection Agency
EPS		Earnings per share
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretation No.
FSP		FASB Staff Position
FTRs		Financial transmission rights
GAAP		U.S. generally accepted accounting principles
Hope		Hope Gas, Inc.
kWh		Kilowatt-hour
LNG		Liquefied natural gas
mcf		Thousand cubic feet
mcfe		Thousand cubic feet equivalent
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
Moody’s		Moody’s Investors Service
MW		Megawatt
MWh		Megawatt-hour
North Anna		North Anna power station
NRC		Nuclear Regulatory Commission
Pennsylvania Commission		Pennsylvania Public Utility Commission
Peoples		The Peoples Natural Gas Company
PJM		PJM Interconnection, LLC
ROE		Return on equity
RTO		Regional transmission organization
SEC		Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
Standard & Poor’s		Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.
U.S.		United States of America
VIEs		Variable interest entities
Virginia Commission		Virginia State Corporation Commission
Virginia Power		Virginia Electric and Power Company
West Virginia Commission		Public Service Commission of West Virginia

PAGE 3

DOMINION RESOURCES, INC.

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008⁽¹⁾			2009		2008⁽¹⁾
(millions, except per share amounts)
Operating Revenue	$	3,450	$	3,399		$	8,228	$	7,752

Operating Expenses
Electric fuel and other energy-related purchases		998		786			2,139		1,567
Purchased electric capacity		105		97			213		204
Purchased gas		368		635			1,506		1,790
Other operations and maintenance		697		804			1,947		1,647
Depreciation, depletion and amortization		271		257			550		511
Other taxes		109		109			266		263

Total operating expenses		2,548		2,688			6,621		5,982

Income from operations		902		711			1,607		1,770

Other income (loss)		70		(1	)		4		(4	)
Interest and related charges⁽²⁾		221		206			441		421

Income from continuing operations including noncontrolling interests before income tax expense		751		504			1,170		1,345
Income tax expense		293		200			460		357

Income from continuing operations including noncontrolling interests		458		304			710		988
Loss from discontinued operations⁽³⁾		—		(2	)		—		(2	)

Net Income Including Noncontrolling Interests		458		302			710		986
Noncontrolling Interests		4		4			8		8

Net Income Attributable to Dominion	$	454	$	298		$	702	$	978

Amounts Attributable to Dominion:
Income from continuing operations, net of tax	$	454	$	300		$	702	$	980
Loss from discontinued operations, net of tax		—		(2	)		—		(2	)

Net income attributable to Dominion	$	454	$	298		$	702	$	978

Earnings Per Common Share – Basic
Income from continuing operations	$	0.76	$	0.52		$	1.19	$	1.70
Loss from discontinued operations		—		—			—		—

Net income attributable to Dominion	$	0.76	$	0.52		$	1.19	$	1.70

Earnings Per Common Share – Diluted
Income from continuing operations	$	0.76	$	0.51		$	1.19	$	1.69
Loss from discontinued operations		—		—			—		—

Net income attributable to Dominion	$	0.76	$	0.51		$	1.19	$	1.69

Dividends paid per common share	$	0.4375	$	0.395		$	0.875	$	0.79

(1)	Our Consolidated Statements of Income for the three and six months ended June 30, 2008 have been recast to reflect the impact of applying SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, as discussed in Note 3.

(2)	Includes affiliated interest expense of $5 million and $9 million for the three months ended June 30, 2009 and 2008, respectively, and $11 million and $23 million for the six months ended June 30, 2009 and 2008, respectively.

(3)	Net of income tax benefit of $3 million for the three and six months ended June 30, 2008.

The accompanying notes are an integral part of our Consolidated Financial Statements.

PAGE 4

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30, 2009			December 31, 2008⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	64		$	66
Customer receivables (less allowance for doubtful accounts of $35 and $32)		1,928			2,354
Other receivables (less allowance for doubtful accounts of $6 and $7)		86			205
Inventories		1,077			1,166
Derivative assets		1,487			1,497
Assets held for sale		1,345			1,416
Regulatory assets		580			340
Prepayments		117			163
Other		427			454

Total current assets		7,111			7,661

Investments
Nuclear decommissioning trust funds		2,310			2,246
Investment in equity method affiliates		710			726
Other		264			285

Total investments		3,284			3,257

Property, Plant and Equipment
Property, plant and equipment		36,893			35,448
Accumulated depreciation, depletion and amortization		(13,019	)		(12,174	)

Total property, plant and equipment, net		23,874			23,274

Deferred Charges and Other Assets
Goodwill		3,503			3,503
Regulatory assets		1,571			2,226
Other		2,154			2,132

Total deferred charges and other assets		7,228			7,861

Total assets	$	41,497		$	42,053

(1)	Our Consolidated Balance Sheet at December 31, 2008 has been derived from the audited Consolidated Financial Statements at that date.

The accompanying notes are an integral part of our Consolidated Financial Statements.

PAGE 5

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30, 2009			December 31, 2008⁽¹⁾
(millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Securities due within one year	$	709		$	444
Short-term debt		1,079			2,030
Accounts payable		1,008			1,499
Accrued interest, payroll and taxes		701			754
Derivative liabilities		893			1,100
Liabilities held for sale		540			570
Accrued dividends		—			260
Other		1,044			1,137

Total current liabilities		5,974			7,794

Long-Term Debt
Long-term debt		13,956			13,890
Junior subordinated notes payable:
Affiliates		268			268
Other		1,483			798

Total long-term debt		15,707			14,956

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		3,810			4,137
Asset retirement obligations		1,539			1,802
Pension and other postretirement benefit liabilities		1,568			1,525
Regulatory liabilities		1,056			944
Other		576			561

Total deferred credits and other liabilities		8,549			8,969

Total liabilities		30,230			31,719

Commitments and Contingencies (see Note 18)
Subsidiary Preferred Stock Not Subject to Mandatory Redemption		257			257

Common Shareholders’ Equity
Common stock – no par⁽²⁾		6,370			5,994
Other paid-in capital		182			182
Retained earnings		4,623			4,170
Accumulated other comprehensive loss		(165	)		(269	)

Total common shareholders’ equity		11,010			10,077

Total liabilities and shareholders’ equity	$	41,497		$	42,053

(1)	Our Consolidated Balance Sheet at December 31, 2008 has been derived from the audited Consolidated Financial Statements at that date.

(2)	1 billion shares authorized; 595 million shares outstanding at June 30, 2009 and 583 million shares outstanding at December 31, 2008.

The accompanying notes are an integral part of our Consolidated Financial Statements.

PAGE 6

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


Six Months Ended June 30,	2009			2008⁽¹⁾
(millions)
Operating Activities
Net income including noncontrolling interests	$	710		$	986
Adjustments to reconcile net income including noncontrolling interests to net cash from operating activities:
Dominion Capital, Inc. impairment loss		—			62
Impairment of gas and oil properties		455			—
Depreciation, depletion and amortization		640			576
Deferred income taxes and investment tax credits		(447	)		322
Other adjustments		33			77
Changes in:
Accounts receivable		623			152
Inventories		40			24
Deferred fuel and purchased gas costs		490			(423	)
Accounts payable		(529	)		(28	)
Accrued interest, payroll and taxes		(43	)		(366	)
Margin deposit assets and liabilities		(137	)		(590	)
Prepayments		(13	)		(216	)
Other operating assets and liabilities		80			(40	)

Net cash provided by operating activities		1,902			536

Investing Activities
Plant construction and other property additions		(1,707	)		(1,509	)
Additions to gas and oil properties		(81	)		(107	)
Proceeds from sale of securities and loan receivable collections and payoffs		727			880
Purchases of securities and loan receivable originations		(760	)		(825	)
Other		33			(110	)

Net cash used in investing activities		(1,788	)		(1,671	)

Financing Activities
Issuance (repayment) of short-term debt, net		(951	)		721
Issuance of long-term debt		1,195			1,830
Repayment of long-term debt		(133	)		(853	)
Repayment of affiliated notes payable		—			(412	)
Issuance of common stock		314			120
Common dividend payments		(516	)		(457	)
Subsidiary preferred dividend payments		(8	)		(8	)
Other		(20	)		(2	)

Net cash provided by (used in) financing activities		(119	)		939

Decrease in cash and cash equivalents		(5	)		(196	)
Cash and cash equivalents at beginning of period⁽²⁾		71			287

Cash and cash equivalents at end of period⁽³⁾	$	66		$	91

Significant Noncash Investing and Financing Activities
Accrued capital expenditures	$	189		$	67
Debt for equity exchange	$	56		$	—

(1)	Our Consolidated Statement of Cash Flow for the six months ended June 30, 2008 has been recast to reflect the impact of applying SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, as discussed in Note 3.

(2)	2009 and 2008 amounts include $5 million and $4 million, respectively, of cash classified as held for sale in our Consolidated Balance Sheets.

(3)	2009 and 2008 amounts include $2 million and $3 million, respectively, of cash classified as held for sale in our Consolidated Balance Sheets.

The accompanying notes are an integral part of our Consolidated Financial Statements.

PAGE 7

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

Dominion Resources, Inc., headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Our operations are conducted through various subsidiaries, including Virginia Electric and Power Company (Virginia Power), our regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. In addition, our operations also include a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, a liquefied natural gas (LNG) import and storage facility in Maryland and regulated gas transportation and distribution operations in Ohio, Pennsylvania and West Virginia. We have entered into an agreement to sell our Pennsylvania and West Virginia gas distribution operations as discussed in Note 4. Our nonregulated operations include merchant generation, energy marketing and price risk management activities, nonregulated retail energy marketing operations and natural gas exploration and production in the Appalachian basin of the U.S.

We manage our daily operations through three primary operating segments: Dominion Virginia Power (DVP), Dominion Energy and Dominion Generation. In addition, we also report a Corporate and Other segment that includes our corporate, service company and other functions and the net impact of certain operations disposed of or to be disposed of, which are discussed in Note 4. Corporate and Other also includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources among the segments. See Note 21 for further discussion of our operating segments.

The terms “Dominion,” “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries or operating segments, or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the SEC, our accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with GAAP. These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in our Annual Report on Form 10-K for the year ended December 31, 2008 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009.

In our opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly our financial position as of June 30, 2009, our results of operations for the three and six months ended June 30, 2009 and 2008 and our cash flows for the six months ended June 30, 2009 and 2008. Such adjustments are normal and recurring in nature unless otherwise noted.

We make certain estimates and assumptions in preparing our Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.

Our accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, our accounts and those of our majority-owned subsidiaries.

In accordance with GAAP, we report certain contracts and instruments at fair value. See Note 9 for further information on fair value measurements in accordance with SFAS No. 157, Fair Value Measurements.

The results of operations for interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales, rate changes, electric fuel and other energy-related purchases, purchased gas expenses and other factors.

Certain amounts in our 2008 Consolidated Financial Statements and Notes have been recast to conform to the 2009 presentation.

PAGE 8

We have evaluated subsequent events through July 31, 2009, the date our Consolidated Financial Statements were issued.

Note 3. Newly Adopted Accounting Standards

SFAS 160

Effective January 1, 2009, we adopted SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements. SFAS No. 160 requires retrospective application of presentation and disclosure changes including that noncontrolling interests be reported as a component of equity and that net income attributable to the parent and noncontrolling interests be separately identified in the income statement.

Our subsidiary preferred dividends were previously included in interest and related charges in our Consolidated Statements of Income and in operating activities in our Consolidated Statements of Cash Flows. Due to the application of SFAS No. 160, we now reflect our subsidiary preferred dividends as an adjustment (noncontrolling interests) to arrive at net income attributable to Dominion in our Consolidated Statements of Income and in financing activities in our Consolidated Statements of Cash Flows. Since our subsidiary preferred stock does not qualify as permanent equity, we continue to report these amounts as mezzanine equity in our Consolidated Balance Sheets.

FSP FAS 115-2 and FAS 124-2

We adopted the provisions of FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (FSP FAS 115-2) effective April 1, 2009. This FSP amends the guidance for the recognition and presentation of other-than-temporary impairments and requires additional disclosures. The recognition provisions of FSP FAS 115-2 apply only to debt securities classified as available for sale or held to maturity, while the presentation and disclosure requirements apply to both debt and equity securities. Prior to the adoption of FSP FAS 115-2, as described in Note 2 in our Annual Report on Form 10-K for the year ended December 31, 2008, we considered all debt securities held by our nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired as we did not have the ability to hold the investments through the anticipated recovery period.

Effective with the adoption of FSP FAS 115-2, using information obtained from our nuclear decommissioning trust fixed-income investment managers, we record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more likely than not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. Additionally, for any debt security that is deemed to have experienced a credit loss, we record the credit loss in earnings and any remaining portion of the unrealized loss in other comprehensive income. We evaluate credit losses primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors. For investments in our utility nuclear decommissioning trusts, all net realized and unrealized gains and losses on debt securities (including any other-than-temporary impairments) continue to be recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation.

Upon the adoption of FSP FAS 115-2 for debt investments held at April 1, 2009, we recorded a $20 million ($12 million after-tax) cumulative effect of a change in accounting principle to reclassify the non-credit related portion of previously recognized other-than-temporary impairments from retained earnings to AOCI, reflecting the fixed-income investment managers’ intent and ability to hold the debt securities until the amortized cost bases are recovered.

Note 4. Dispositions

Sale of Certain DCI Operations

Previously, Dominion Capital, Inc. (DCI) held an investment in the subordinated notes of a third-party collateralized debt obligation (CDO) entity, which we consolidated in accordance with FIN 46R (revised December 2003), Consolidation of Variable Interest Entities. In March 2008, we reached an agreement to sell our remaining interest in the subordinated notes, effectively eliminating the variability of our interest, and therefore deconsolidated the CDO entity as of March 31, 2008 and recognized impairment losses of $62 million ($38 million after-tax) in other operations and maintenance expense. In connection with the sale of the subordinated notes, in April 2008, we received proceeds of $54 million, including accrued interest.

Planned Sale of Regulated Gas Distribution Subsidiaries

In July 2008, we entered into an agreement with Peoples Hope Gas Companies LLC, a subsidiary of Babcock & Brown Infrastructure Fund North America (the Fund), to sell Peoples and Hope for approximately $910 million,

PAGE 9

subject to adjustments to reflect levels of capital expenditures and changes in working capital. In May 2009, the Fund’s management team established a new entity, SteelRiver Infrastructure Partners LP (SteelRiver), to acquire the general partner of the Fund from Babcock & Brown. John Hancock Life Insurance Company (John Hancock) acquired Babcock & Brown’s limited partner interests in the Fund. Management rights over the Fund were acquired by an entity jointly owned by SteelRiver and John Hancock and will be managed under contract with SteelRiver. The transactions described in the three preceding sentences are referred to as the SteelRiver Transaction. The Peoples and Hope transaction is expected to close in 2009, subject to regulatory approvals in Pennsylvania and West Virginia.

The carrying amounts of the major classes of assets and liabilities associated with the planned sale of Peoples and Hope and classified as held for sale in our Consolidated Balance Sheets are as follows:


	June 30, 2009			December 31, 2008
(millions)
ASSETS
Current Assets
Customer receivables	$	93		$	172
Other		126			142

Total current assets		219			314

Property, Plant and Equipment
Property, plant and equipment		1,221			1,204
Accumulated depreciation, depletion and amortization		(353	)		(358	)

Total property, plant and equipment, net		868			846

Deferred Charges and Other Assets
Regulatory assets		158			156
Other		100			100

Total deferred charges and other assets		258			256

Assets held for sale	$	1,345		$	1,416

LIABILITIES
Current Liabilities	$	146		$	192
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		304			289
Other		90			89

Total deferred credits and other liabilities		394			378

Liabilities held for sale	$	540		$	570

The following table presents selected information regarding the results of operations of Peoples and Hope, which are included in income from continuing operations including noncontrolling interests:


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
(millions)
Operating revenue	$	86	$	101	$	401	$	406
Income before income taxes⁽¹⁾		11		50		56		100

(1)	Income before taxes for the three and six months ended June 30, 2008 includes a $47 million benefit related to the re-establishment of a regulatory asset in connection with the pending SteelRiver transaction.

PAGE 10

Note 5. Operating Revenue

Our operating revenue consists of the following:


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
(millions)
Operating Revenue
Electric sales:
Regulated	$	1,647	$	1,514	$	3,472	$	3,010
Nonregulated		924		779		1,918		1,664
Gas sales:
Regulated		92		189		608		791
Nonregulated		379		572		1,291		1,423
Gas transportation and storage		299		221		719		610
Other		109		124		220		254

Total operating revenue	$	3,450	$	3,399	$	8,228	$	7,752

Note 6. Income Taxes

A reconciliation of income taxes at the U.S. statutory federal rate as compared to the income tax expense recorded in our Consolidated Statements of Income is presented below:


	Six Months Ended June 30,
	2009		2008
U.S. statutory rate	35.0	%	35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit	5.0		2.7
Reversal of deferred taxes – stock of subsidiaries held for sale	—		(10.1	)
Changes in valuation allowances	0.1		1.2
Legislative changes	—		(1.0	)
Other, net	(0.8	)	(1.2	)

Effective tax rate	39.3	%	26.6	%

In 2008, our effective tax rate reflected the reversal of $136 million of deferred tax liabilities, recognized in 2006, associated with the excess of our financial reporting basis over the tax basis in the stock of Peoples and Hope, in accordance with EITF Issue No. 93-17, Recognition of Deferred Tax Assets for a Parent Company’s Excess Tax Basis in the Stock of a Subsidiary that is Accounted for as a Discontinued Operation. Although these subsidiaries are not classified as discontinued operations, EITF 93-17 requires that the deferred tax impact of the excess of the financial reporting basis over the tax basis of a parent’s investment in a subsidiary be recognized when it is apparent that this difference will reverse in the foreseeable future. In 2006, based on the intended form of the sale to Equitable Resources, Inc. (Equitable), we recognized these deferred tax liabilities since this difference was expected to reverse upon closing of the sale.

In January 2008, Dominion and Equitable agreed to terminate the agreement for the sale of Peoples and Hope. At that time, based on our expectation that the form of any future disposal of these subsidiaries would be structured so that the taxable gain would instead be determined by reference to the basis in the subsidiaries’ underlying assets, we reversed the related deferred tax liabilities recognized in 2006. As discussed in Note 4, we have executed a new agreement to sell Peoples and Hope, whereby we will determine our taxable gain by reference to the basis in the subsidiaries’ underlying assets.

PAGE 11

As the result of West Virginia legislative changes enacted in the first quarter of 2008 that provided for income tax rate reductions, to be phased in during the period 2009 through 2014, we reduced our net deferred tax liabilities by $13 million.

In the second quarter of 2009, the U.S. Congressional Joint Committee on Taxation completed its review of our settlement with the Appellate Division of the Internal Revenue Service (IRS Appeals) for tax years 1999 through 2001. Settlement negotiations with IRS Appeals regarding our protest of adjustments proposed for tax years 2002 and 2003 are ongoing. In addition, the Internal Revenue Service has completed its audit and has proposed adjustments for tax years 2004 and 2005. We filed protests for certain of those adjustments in July 2009.

At June 30, 2009, unrecognized tax benefits related to current year tax positions were $26 million. During the six months ended June 30, 2009, unrecognized tax benefits related to prior year uncertain tax positions increased on a gross basis by $32 million and decreased on a gross basis by $45 million. In addition, unrecognized tax benefits for prior years decreased by $11 million for settlements with tax authorities and $20 million for amounts that otherwise become deductible in 2009.

For a discussion of reasonably possible changes that could occur in our unrecognized tax benefits during the next twelve months, see Note 7 to our Annual Report on Form 10-K for the year ended December 31, 2008. In addition, with the completion of the audit of tax years 2004 and 2005, it is reasonably possible that unrecognized tax benefits could decrease up to $50 million over the next twelve months, resulting from successful settlement negotiations or payments to tax authorities, with no material impact on our results of operations.

Note 7. Earnings Per Share

The following table presents the calculation of our basic and diluted EPS:


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
(millions, except EPS)
Net income attributable to Dominion	$	454	$	298	$	702	$	978

Average shares of common stock outstanding – Basic		593.7		577.1		589.5		576.2
Net effect of potentially dilutive securities⁽¹⁾		0.3		3.6		0.4		3.3

Average shares of common stock outstanding – Diluted		594.0		580.7		589.9		579.5

Earnings Per Common Share – Basic	$	0.76	$	0.52	$	1.19	$	1.70
Earnings Per Common Share – Diluted	$	0.76	$	0.51	$	1.19	$	1.69

(1)	Potentially dilutive securities consist of options, goal-based stock and contingently convertible senior notes.

Potentially dilutive securities with the right to acquire approximately 2.7 million and 2.2 million common shares for the three and six months ended June 30, 2009, respectively, were not included in the respective period’s calculation of diluted EPS because the exercise or purchase prices of those instruments were greater than the average market price of our common shares. There were no such anti-dilutive securities outstanding during the three and six months ended June 30, 2008.

PAGE 12

Note 8. Comprehensive Income

The following table presents total comprehensive income:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
(millions)
Net income including noncontrolling interests	$	458		$	302		$	710		$	986
Other comprehensive income (loss):
Net other comprehensive income (loss) associated with effective portion of changes in fair value of derivatives designated as cash flow hedges, net of taxes and amounts reclassified to earnings		(112	)⁽¹⁾		(787	)⁽²⁾		39			(1,123	)⁽²⁾
Other, net of tax		53	⁽³⁾		(4	)		77	⁽³⁾		(60	)⁽⁴⁾

Other comprehensive income (loss)		(59	)		(791	)		116			(1,183	)

Comprehensive income (loss) including noncontrolling interests		399			(489	)		826			(197	)
Noncontrolling interests		4			4			8			8

Total comprehensive income (loss) attributable to Dominion	$	395		$	(493	)	$	818		$	(205	)

(1)	Principally reflects the reclassification of electricity-related derivative activity to earnings.

(2)	Primarily due to the impact of an increase in commodity prices.

(3)	Principally represents a net increase in unrealized gains on investments held in merchant nuclear decommissioning trusts.

(4)	Primarily represents a reduction in unrealized gains on investments held in merchant nuclear decommissioning trusts.

Other comprehensive income (loss) for the three and six months ended June 30, 2009 excludes a $20 million ($12 million after-tax) adjustment representing the cumulative effect of the change in accounting principle related to the adoption of FSP FAS 115-2.

Note 9. Fair Value Measurements

Our fair value measurements are made in accordance with the policies discussed in Note 8 to our Annual Report on Form 10-K for the year ended December 31, 2008. In addition, see Note 10 in this report for further information about our derivatives and hedge accounting activities.

The following table presents our assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:


	Level 1		Level 2		Level 3		Total
(millions)
As of June 30, 2009
Assets
Derivatives	$	140	$	1,765	$	135	$	2,040
Investments		920		1,375		—		2,295

Total assets	$	1,060	$	3,140	$	135	$	4,335

Liabilities
Derivatives	$	14	$	979	$	104	$	1,097

As of December 31, 2008
Assets
Derivatives	$	125	$	1,672	$	243	$	2,040
Investments		725		1,501		—		2,226

Total assets	$	850	$	3,173	$	243	$	4,266

Liabilities
Derivatives	$	7	$	1,146	$	144	$	1,297

PAGE 13

The following table presents the net change in the assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
(millions)
Beginning balance	$	98		$	(72	)	$	99		$	(61	)
Total realized and unrealized gains or (losses):
Included in earnings		(69	)		54			(131	)		63
Included in other comprehensive income (loss)		(108	)		(327	)		(88	)		(377	)
Included in regulatory assets/liabilities		32			167			55			200
Purchases, issuances and settlements		78			(11	)		112			(12	)
Transfers out of Level 3		—			(2	)		(16	)		(4	)

Ending balance	$	31		$	(191	)	$	31		$	(191	)

The amount of gains (losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets still held at the reporting date	$	3		$	20		$	(10	)	$	21

The following table presents gains and losses included in earnings in the Level 3 fair value category:


	Operating revenue			Electric fuel and other energy-related purchases			Purchased gas			Total
(millions)
Three Months Ended June 30, 2009
Total gains or (losses) included in earnings	$	18		$	(87	)	$	—		$	(69	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets/liabilities still held at the reporting date		3			—			—			3

Three Months Ended June 30, 2008
Total gains or (losses) included in earnings	$	(36	)	$	71		$	19		$	54
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets/liabilities still held at the reporting date		(13	)		15			18			20

Six Months Ended June 30, 2009
Total gains or (losses) included in earnings	$	14		$	(138	)	$	(7	)	$	(131	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets/liabilities still held at the reporting date		(4	)		(1	)		(5	)		(10	)

Six Months Ended June 30, 2008
Total gains or (losses) included in earnings	$	(51	)	$	89		$	25		$	63
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets/liabilities still held at the reporting date		(16	)		15			22			21

As of June 30, 2009, our net balance of commodity derivatives categorized as Level 3 fair value measurements was a net asset of $31 million. A hypothetical 10% increase in commodity prices would decrease the net asset by $34 million, while a hypothetical 10% decrease in commodity prices would increase the net asset by $35 million.

Additionally, during the first quarter of 2009, we evaluated an equity method investment for impairment and recorded a $23 million impairment in other income (loss) in our Consolidated Statement of Income. The resulting

PAGE 14

fair value of $10 million was estimated using an expected present value cash flow model and is considered a Level 3 fair value measurement due to the use of significant unobservable inputs related to the timing and amount of future equity distributions based on the investee’s future financing structure, contractual and market based revenues and operating costs.

There were no significant non-financial assets or liabilities that were measured at fair value on a nonrecurring basis during the six months ended June 30, 2009.

Fair Value of Financial Instruments

Substantially all of our financial instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. At June 30, 2009 and December 31, 2008, the carrying amount of our cash and cash equivalents, customer and other receivables, short-term debt and accounts payable are representative of fair value due to the short-term nature of these instruments. The financial instruments’ carrying amounts and fair values are as follows:

June 30, 2009

December 31, 2008

Carrying
Amount

Estimated Fair
Value⁽¹⁾

Carrying
Amount

Estimated Fair
Value⁽¹⁾

(millions)

Long-term debt⁽²⁾

14,665

15,482

14,334

14,260

Junior subordinated notes payable to:

Affiliates

268

219

268

234

Other

1,483

1,283

798

409

Subsidiary preferred stock⁽³⁾

257

231

257

231

(1)

Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2)	Includes securities due within one year and amounts which represent the unamortized discount and premium. Also includes the valuation of certain fair value hedges associated with our fixed rate debt of $12 million and $15 million at June 30, 2009 and December 31, 2008, respectively.

(3)	Includes issuance expenses of $2 million at June 30, 2009 and December 31, 2008.

Note 10. Derivatives and Hedge Accounting Activities

Our accounting policies and objectives and strategies for using derivative instruments are discussed in Note 2 to our Annual Report on Form 10-K for the year ended December 31, 2008.

The following table presents the volume of our derivative activity as of June 30, 2009. These volumes are based on open derivative positions and represent the combined absolute value of our long and short positions, except in the case of offsetting deals, for which we present the absolute value of the net volume of our long and short positions.


	Current		Noncurrent
Natural Gas (bcf):
Fixed price⁽¹⁾		643.4		350.7
Basis		1,070.0		589.7
Electricity (MWh):
Fixed price⁽¹⁾		18,925,788		11,913,818
FTRs		98,841,824		—
Capacity (MW)		767,820		5,971,700
Liquids (gallons)⁽²⁾		170,123,555		207,816,000
Interest rate	$	970,000,000	$	1,925,000,000
Foreign currency (euros)		9,847,638		4,000,000

(1)

Includes options.

(2)

Includes natural gas liquids and oil.

For the three and six months ended June 30, 2009 and 2008, gains or losses on hedging instruments determined to be ineffective were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices and were not material for the three and six months ended June 30, 2009 and 2008.

PAGE 15

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in our Consolidated Balance Sheet at June 30, 2009:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(12	)	$	(16	)	48 months
Electricity		432			312		30 months
Natural gas liquids		44			24		30 months
Other		3			2		71 months
Interest rate		78			(5	)	378 months
Foreign currency		1			1		65 months

Total	$	546		$	318

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices, interest rates and foreign exchange rates.

Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of our derivatives as of June 30, 2009 and where they are recorded on our Consolidated Balance Sheet:


	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
ASSETS
Current Assets
Commodity	$	887	$	534	$	1,421
Interest rate		65		—		65
Foreign currency		1		—		1

Total current derivative assets		953		534		1,487

Noncurrent Assets
Commodity		316		129		445
Interest rate		107		—		107
Foreign currency		1		—		1

Total noncurrent derivative assets⁽¹⁾		424		129		553

Total derivative assets	$	1,377	$	663	$	2,040

LIABILITIES
Current Liabilities
Commodity	$	314	$	575	$	889
Interest rate		4		—		4

Total current derivative liabilities		318		575		893

Noncurrent Liabilities
Commodity		63		140		203
Interest rate		1		—		1

Total noncurrent derivative liabilities⁽²⁾		64		140		204

Total derivative liabilities	$	382	$	715	$	1,097

(1)	Noncurrent derivative assets are recorded in other deferred charges and other assets on our Consolidated Balance Sheet.

(2)	Noncurrent derivative liabilities are recorded in other deferred credits and other liabilities on our Consolidated Balance Sheet.

PAGE 16

The following tables present the gains and losses on our derivatives, as well as where the associated activity is presented on our Consolidated Balance Sheet and Statement of Income:


Derivatives in SFAS No. 133 Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)⁽¹⁾			Amount of Gain (Loss) Reclassified from AOCI to Income			Increase (decrease) in Derivatives Subject to Regulatory Treatment⁽²⁾
(millions)
Three Months Ended June 30, 2009
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue				$	284
Purchased gas					(35	)
Electric fuel and other energy-related purchases					(2	)
Purchased electric capacity					1

Total commodity	$	(57	)		248		$	(4	)

Interest rate⁽³⁾		138			(1	)		86
Foreign currency⁽⁴⁾		1			—			2

Total	$	82		$	247		$	84

Six Months Ended June 30, 2009
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue				$	522
Purchased gas					(83	)
Electric fuel and other energy-related purchases					(7	)
Purchased electric capacity					3

Total commodity	$	374			435		$	1

Interest rate⁽³⁾		124			(2	)		73
Foreign currency⁽⁴⁾		1			1			—

Total	$	499		$	434		$	74

(1)	Amounts deferred into AOCI have no associated effect in our Consolidated Statements of Income.

(2)	Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in our Consolidated Statements of Income.

(3)	Amounts recorded in our Consolidated Statements of Income are classified in interest expense.

(4)	Amounts recorded in our Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.


	Amount of Gain (Loss) Recognized in Income on Derivatives⁽¹⁾
Derivatives not designated as hedging instruments under SFAS No. 133	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	13		$	46
Purchased gas		(14	)		(46	)
Electric fuel and other energy-related purchases		(86	)		(137	)

Total	$	(87	)	$	(137	)

(1)	Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect on our Consolidated Statements of Income.

PAGE 17

For the three and six months ended June 30, 2009, there were no significant gains or losses recorded related to fair value hedging relationships.

See Note 9 for further information about fair value measurements and associated valuation methods for derivatives under SFAS No. 157.

Note 11. Investments

Rabbi Trust Securities

Marketable equity and debt securities and cash equivalents held in our rabbi trusts and classified as trading totaled $85 million and $95 million at June 30, 2009 and December 31, 2008, respectively. Cost-method investments held in our rabbi trusts totaled $18 million and $21 million at June 30, 2009 and December 31, 2008, respectively.

Decommissioning Trust Securities

We hold marketable equity and debt securities and cash equivalents (classified as available-for-sale) and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for our nuclear plants. Our decommissioning trust funds are summarized below.


	Amortized Cost		Total Unrealized Gains⁽¹⁾		Total Unrealized Losses⁽¹⁾			Fair Value
(millions)
June 30, 2009
Marketable equity securities	$	1,107	$	162	$	—		$	1,269
Marketable debt securities:
Corporate bonds		233		7		(6	)		234
U.S. Treasury securities and agency debentures		293		13		(1	)		305
State and municipal		362		15		(8	)		369
Other		2		—		—			2
Cost method investments		95		—		—			95
Cash equivalents and other⁽²⁾		36		—		—			36

Total	$	2,128	$	197	$	(15	)⁽³⁾	$	2,310

December 31, 2008
Marketable equity securities	$	1,022	$	26	$	—		$	1,048
Marketable debt securities:
Corporate bonds		238		11		—			249
U.S. Treasury securities and agency debentures		371		16		—			387
State and municipal		386		14		—			400
Other		6		1		—			7
Cost method investments		108		—		—			108
Cash equivalents and other⁽²⁾		47		—		—			47

Total	$	2,178	$	68	$	—		$	2,246

(1)	Included in AOCI and the decommissioning trust regulatory liability.

(2)	Includes net assets related to pending sales and purchases of securities of $7 million and $8 million at June 30, 2009 and December 31, 2008, respectively.

(3)	The fair value of securities in an unrealized loss position was $218 million at June 30, 2009.

PAGE 18

The fair value of our marketable debt securities at June 30, 2009, by contractual maturity is as follows:


	Amount
(millions)
Due in one year or less	$	77
Due after one year through five years		222
Due after five years through ten years		280
Due after ten years		331

Total	$	910

Presented below is selected information regarding our marketable equity and debt securities.


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
(millions)
Trading securities:
Net unrealized gain (loss)	$	6	$	(2	)	$	2	$	(11	)
Available-for-sale securities:
Proceeds from sales⁽¹⁾		438		177			727		402
Realized gains⁽²⁾		45		20			61		39
Realized losses⁽²⁾		16		59			159		122

(1)	The increase in proceeds primarily reflects changes in asset allocation and liquidation of positions in connection with changes in fund managers.

(2)	Includes realized gains and losses recorded to the decommissioning trust regulatory liability.

We recorded other-than-temporary impairment losses on investments as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
(millions)
Total other-than-temporary impairment losses⁽¹⁾	$	15		$	51		$	156		$	100
Losses recorded to decommissioning trust regulatory liability		(7	)		(17	)		(70	)		(34	)
Losses recognized in other comprehensive income (before taxes)		(1	)		—			(1	)		—

Net impairment losses recognized in earnings	$	7		$	34		$	85		$	66

(1)	Amount includes other-than-temporary impairment losses for debt securities of $2 million and $6 million for the three months ended June 30, 2009 and 2008, respectively, and $8 million and $12 million for the six months ended June 30, 2009 and 2008, respectively.

PAGE 19

Note 12. Regulatory Assets and Liabilities

Our regulatory assets and liabilities include the following:


	June 30, 2009		December 31, 2008
(millions)
Regulatory assets
Deferred cost of fuel used in electric generation⁽¹⁾	$	463	$	133
Unrecovered gas costs⁽²⁾		53		107
Other		64		100

Regulatory assets –current		580		340

Unrecognized pension and other postretirement benefit costs⁽³⁾		1,078		1,090
PIPP⁽⁴⁾		159		131
RTO start-up costs and administration fees⁽⁵⁾		131		135
Deferred cost of fuel used in electric generation⁽¹⁾		15		676
Other		188		194

Regulatory assets –non-current		1,571		2,226

Total regulatory assets	$	2,151	$	2,566

Regulatory liabilities
Provision for future cost of removal and AROs⁽⁶⁾	$	720	$	688
Decommissioning trust⁽⁷⁾		221		213
Other⁽⁸⁾		148		63

Total regulatory liabilities	$	1,089	$	964

(1)

As discussed under Virginia Fuel Expenses in Note 18, in March 2009 we filed our Virginia fuel factor application with the Virginia Commission which requested an annual decrease in fuel expense recovery of approximately $236 million for the period July 1, 2009 through June 30, 2010. The proposed fuel factor went into effect on July 1, 2009 on an interim basis and an evidentiary hearing on the Company’s application was to be held on July 16, 2009. In a subsequent order, the Virginia Commission postponed the July 16^th hearing until September 1, 2009.

(2)	Primarily reflects prior period unrecovered gas costs at Dominion East Ohio, which are recovered through quarterly filings with the Public Utilities Commission of Ohio.

(3)	Represents unrecognized pension and other postretirement benefit costs expected to be recovered through future rates by certain of our rate-regulated subsidiaries.

(4)

Under the Ohio Percentage of Income Payment Plan (PIPP), eligible customers can receive energy assistance based on their ability to pay. The difference between the customer’s total bill and the PIPP plan amount is deferred and collected under the PIPP rider according to Dominion East Ohio tariff provisions. Although the current rider rate was designed to recover deferred costs over a three-year period, unrecovered costs have increased. Accordingly, Dominion East Ohio plans to file for approval to amend the recovery rate in the third quarter of 2009.

(5)

The FERC has approved our recovery of start-up costs incurred in connection with joining an RTO and ongoing administrative charges paid to PJM through a Deferral Recovery Charge (DRC). As discussed in Note 18, in June 2009, the Virginia Commission approved full recovery of the DRC from retail customers. In July 2009, FERC issued an order denying requests for rehearing of its December 2008 order. The time to appeal FERC’s orders has not yet expired. Recovery of the DRC, over a ten year period, will begin September 1, 2009. Approximately $19 million of these costs are included in other current regulatory assets.

(6)	Rates charged to customers by our regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.

(7)

Primarily reflects a regulatory liability established in 2007 representing amounts previously collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of our utility nuclear generation stations, in excess of amounts recorded pursuant to SFAS No. 143, Accounting for Asset Retirement Obligations.

(8)	Includes $33 million and $20 million reported in other current liabilities at June 30, 2009 and December 31, 2008, respectively.

At June 30, 2009, approximately $651 million of our regulatory assets represented past expenditures on which we do not earn a return. These expenditures consist primarily of deferred fuel costs that are expected to be recovered within two years.

PAGE 20

Note 13. Asset Retirement Obligations

The following table describes the changes in our AROs during 2009:


	Amount
(millions)
AROs at December 31, 2008⁽¹⁾	$	1,822
Obligations incurred during the period		1
Obligations settled during the period		(5	)
Revisions in estimated cash flows⁽²⁾		(307	)
Accretion		45

AROs at June 30, 2009⁽¹⁾	$	1,556

(1)	Includes $20 million and $17 million reported in other current liabilities at December 31, 2008 and June 30, 2009, respectively.

(2)	Primarily reflects updated decommissioning cost studies and applicable escalation rates received for each of our nuclear facilities during the second quarter of 2009.

During the three months ended June 30, 2009, we recorded a $103 million ($62 million after-tax) reduction in other operations and maintenance expense due to a downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service.

Note 14. Ceiling Test

We follow the full cost method of accounting for gas and oil E&P activities prescribed by the SEC. Under the full cost method, capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves, discounted at 10%, assuming period-end hedge-adjusted prices. If net capitalized costs exceed the ceiling at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.

Approximately 3% of our anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Using period-end hedge-adjusted prices, there was no ceiling test impairment as of June 30, 2009. Excluding the effects of hedge-adjusted prices in calculating the ceiling limitation would have resulted in a $79 million ($47 million after-tax) ceiling test impairment at June 30, 2009.

At March 31, 2009, due to declines in natural gas and oil prices, we recorded a ceiling test impairment charge of $455 million ($281 million after-tax, including a subsequent $9 million increase for estimated state taxes recorded in the second quarter of 2009) in other operations and maintenance expense in our Consolidated Statement of Income. Excluding the effects of hedge-adjusted prices in calculating the ceiling limitation, the impairment would have been $631 million ($387 million after-tax, including a subsequent update for estimated state taxes recorded in the second quarter of 2009).

Commodity prices are subject to significant volatility. If the current price environment deteriorates, it could potentially result in a write-down of our natural gas and oil properties when we perform our September 30, 2009 quarterly ceiling test. While we cannot currently predict the impact of a ceiling test impairment on our results of operations, it would have no impact on our cash flows and we would not expect a material impact on our financial condition.

Note 15. Variable Interest Entities

As discussed in Note 16 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008, certain variable pricing terms in some of our long-term power and capacity contracts cause them to be considered variable interests in the counterparties in accordance with FIN 46R.

We have long-term power and capacity contracts with four non-utility generators with an aggregate generation capacity of approximately 940 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that we consider to be variable interests. After an evaluation of the information provided to us by these entities, we were unable to determine whether they were variable interest entities (VIEs). However, the information they provided, as well as our knowledge of generation facilities in Virginia, enabled us to conclude that, if they were VIEs, we would not be the primary beneficiary. This conclusion was based primarily on a qualitative assessment of our variable interests as compared to the operations, commodity price and other risks retained by the

PAGE 21

entities’ equity and debt holders during the remaining terms of our contracts and for the years the entities are expected to operate after our contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. We are not subject to any risk of loss from these potential VIEs other than our remaining purchase commitments which totaled $1.9 billion as of June 30, 2009. We paid $51 million and $50 million for electric capacity and $25 million and $45 million for electric energy to these entities for the three months ended June 30, 2009 and 2008, respectively. We paid $104 million and $102 million for electric capacity and $66 million and $92 million for electric energy to these entities for the six months ended June 30, 2009 and 2008, respectively.

Note 16. Significant Financing Transactions

Credit Facilities and Short-Term Debt

We use short-term debt, primarily commercial paper, to fund working capital requirements, as a bridge to long-term debt financing and as interim financing for acquisitions, if applicable. The levels of our borrowings may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, we utilize cash and letters of credit to fund collateral requirements under our commodities hedging program. Collateral requirements are impacted by commodity prices, hedging levels and our credit quality and the credit quality of our counterparties.

Our credit facility commitments are with a large consortium of banks, which included Lehman Brothers Holdings Inc. (Lehman). In March 2009, we executed a consent agreement with the bank syndicates to reduce Lehman’s remaining commitment to zero in each of our credit facilities in which it had participated.

At June 30, 2009, we had the following amounts outstanding and capacity available under our credit facilities:


	Facility Limit		Outstanding Commercial Paper		Outstanding Bank Borrowings		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Five-year joint revolving credit facility⁽¹⁾	$	2,872	$	379	$	—	$	291	$	2,202
Five-year Dominion credit facility⁽²⁾		1,700		—		700		40		960
Five-year Dominion bilateral facility⁽³⁾		200		—		—		72		128
364-day Dominion credit facility⁽⁴⁾		467		—		—		—		467

Totals	$	5,239	$	379	$	700	$	403	$	3,757

(1)	This credit facility was entered into in February 2006 and terminates in February 2011. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.

(2)	This credit facility was entered into in August 2005 and terminates in August 2010. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

(3)	This facility was entered into in December 2005 and terminates in December 2010. This facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

(4)	This credit facility was entered into in July 2008 and could be used to support bank borrowings and the issuance of commercial paper. We did not renew this facility prior to its expiration in July 2009.

In addition to the credit facility commitments disclosed above, we also have a five-year credit facility that supports certain Virginia Power tax-exempt financings. In June 2009, the committed amount was reduced from $182 million to $120 million. The reduced amount reflects the size necessary to cover outstanding variable rate tax-exempt financing.

Long-Term Debt

In May 2009, Brayton Point power station (Brayton Point) borrowed $50 million in connection with the Massachusetts Development Finance Agency Solid Waste Disposal Revenue Refunding Bonds Series 2009, which mature in 2042 and bear a coupon rate of 5.75% for the first ten years, after which they will bear interest at a market rate to be determined at that time, using a remarketing process. The proceeds were used to finance certain improvements at Brayton Point.

In May 2009, Virginia Power borrowed $40 million in connection with the Economic Development Authority of the County of Chesterfield Pollution Control Refunding Revenue Bonds, Series 2009 A, which mature in 2023 and bear a coupon rate of 5.0%. The proceeds were used to refund the principal amount of the Industrial Development Authority of the County of Chesterfield Money Market Municipals ^TM Pollution Control Revenue Bonds, Series 1985 that would otherwise have matured in October 2009.

PAGE 22

In May 2009, Virginia Power borrowed $70 million in connection with the Economic Development Authority of York County, Virginia Pollution Control Refunding Revenue Bonds, Series 2009 A, which mature in 2033 and bear an initial coupon rate of 4.05% for the first five years, after which they will bear interest at a market rate to be determined at that time, using a remarketing process. The proceeds were used to refund the principal amount of the Industrial Development Authority of York County, Virginia Money Market Municipals^TM Pollution Control Revenue Bonds, Series 1985 that would otherwise have matured in July 2009.

In June 2009, Virginia Power issued $350 million of 5.0% senior notes that mature in 2019. The proceeds were used for general corporate purposes and the repayment of short-term debt, including commercial paper.

In June 2009, Dominion issued $685 million (including $60 million related to the underwriter’s option to purchase additional notes to cover over-allotments) of its 8.375% Series A Enhanced Junior Subordinated Notes (hybrids) that will mature in 2064, subject to extensions to no later than 2079. The proceeds were used for general corporate purposes. The hybrids are listed on the New York Stock Exchange under the symbol DRU.

We repaid $133 million of long-term debt during the six months ended June 30, 2009.

Convertible Securities

We have $202 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of our common stock under certain circumstances. The conversion feature requires that the principal amount of each note be repaid in cash, while amounts payable in excess of the principal amount will be paid in common stock. The conversion rate is subject to adjustment upon certain events such as subdivisions, splits, combinations of common stock or the issuance to all common stock holders of certain common stock rights, warrants or options and certain dividend increases. As of June 30, 2009, the conversion rate has been adjusted, primarily due to individual dividend payments above the level paid at issuance, to 27.9368 shares of common stock per $1,000 principal amount of senior notes, which represents a conversion price of $35.80.

The senior notes have not been eligible for conversion during 2009 and as of June 30, 2009, the closing price of our common stock was not higher than $42.95 per share for at least 20 out of the last 30 consecutive trading days, therefore, the senior notes are also not eligible for conversion during the third quarter of 2009.

Issuance of Common Stock

During the six months ended June 30, 2009, we issued 10 million shares of common stock and received cash proceeds of $314 million. We issued 6.2 million shares through at-the-market issuances under our sales agency agreements and received cash proceeds of $191 million, net of fees and commissions paid of $2 million. The remainder of the shares issued and cash proceeds received during the six months ended June 30, 2009 were through Dominion Direct^®, employee savings plans and the exercise of employee stock options.

In February 2009, we also issued approximately 1.6 million shares of common stock to an existing holder of our senior notes, in a privately negotiated transaction, in exchange for approximately $56 million of the principal of two series of our outstanding senior notes, which were retired. The transaction was exempt from registration pursuant to Section 3(a)(9) of the Securities Act and no commission or remuneration was paid in connection with the exchange.

Following these issuances, we have $207 million of remaining stock issuance authorization under sales agency agreements; however, we expect remaining 2009 equity needs to be met by proceeds from Dominion Direct^®, employee savings plans and the exercise of employee stock options.

Note 17. Stock-Based Awards

Our results for the three months ended June 30, 2009 and 2008 include $11 million and $12 million, respectively, of compensation costs and $4 million and $5 million, respectively, of income tax benefits related to our stock-based compensation arrangements. Our results for the six months ended June 30, 2009 and 2008 include $22 million and $19 million, respectively, of compensation costs and $8 million and $7 million, respectively, of income tax benefits related to our stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in our Consolidated Statements of Income. SFAS No. 123R, Share-Based Payment, requires the benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation (excess tax benefits) to be classified as a financing cash flow. Approximately $2 million and $7 million of excess tax benefits were realized for the six months ended June 30, 2009 and 2008, respectively.

PAGE 23

Stock Options

The following table provides a summary of changes in amounts of stock options outstanding during 2009:


	Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Life	Aggregated Intrinsic Value⁽¹⁾
	(thousands)				(years)	(millions)
Outstanding and exercisable at January 1, 2009	5,558		$	30.53
Exercised	(484	)		27.31		$	3
Forfeited/expired	(30	)		28.89

Outstanding and exercisable at June 30, 2009	5,044		$	30.85	1.81	$	13

(1)	Intrinsic value represents the difference between the exercise price of the option and the market value of our stock.

We issue new shares to satisfy stock option exercises. We received cash proceeds from the exercise of stock options of approximately $15 million and $20 million in the six months ended June 30, 2009 and 2008, respectively.

Restricted Stock

The fair value of our restricted stock awards is equal to the market price of our stock on the date of grant. These awards generally vest over a three-year service period and are settled by issuing new shares. The following table provides a summary of restricted stock activity during 2009:


	Shares		Weighted-Average Grant Date Fair Value
	(thousands)
Nonvested at January 1, 2009	1,756		$	38.55
Granted	525			33.84
Vested	(866	)		34.48
Cancelled and forfeited	(48	)		38.51
Converted from goal-based stock to restricted stock	185			44.18

Nonvested at June 30, 2009	1,552		$	39.91

As of June 30, 2009, unrecognized compensation cost related to nonvested restricted stock awards totaled approximately $33 million and is expected to be recognized over a weighted-average period of 1.5 years.

Goal-Based Stock

Goal-based stock awards are generally granted to key non-officer employees on an annual basis. Goal-based stock awards are also granted in lieu of cash-based performance grants to certain officers who have not achieved a certain targeted level of share ownership. The issuance of awards is based on the achievement of multiple performance metrics during a two-year period, including return on invested capital, book value per share and total shareholder return relative to that of a peer group of companies.

The actual number of shares issued will vary between zero and 200% of targeted shares depending on the level of performance metrics achieved. The fair value of goal-based stock is equal to the market price of our stock on the date of grant. Goal-based stock awards granted to key non-officer employees convert to restricted stock at the end of the two-year performance period and generally vest three years from the original grant date. Awards to officers vest at the end of the two-year performance period. All goal-based stock awards are settled by issuing new shares. Current outstanding goal-based shares include awards granted in April 2008, February 2009 and April 2009.

After the performance period for the April 2007 grants ended on December 31, 2008, the Compensation, Governance and Nominating Committee determined the actual performance against metrics established for those awards. For awards to key non-officer employees, 127 thousand shares of the outstanding goal-based stock awards granted in April 2007 were converted to 185 thousand shares of restricted stock for the remaining term of the vesting period ending in April 2010. For awards to officers, 27 thousand shares of the outstanding goal-based stock awards were converted to 38 thousand non-restricted shares and issued to the officers.

PAGE 24

For remaining goal-based stock awards, at June 30, 2009, the targeted number of shares to be issued is 324 thousand. The following table provides a summary of goal-based stock activity during 2009:


	Targeted Number of Shares		Weighted-Average Grant Date Fair Value
	(thousands)
Nonvested at January 1, 2009	315		$	42.56
Granted	163			31.41
Vested	(27	)		44.49
Converted from goal-based stock to restricted stock	(127	)		44.18

Nonvested at June 30, 2009	324		$	36.13

At June 30, 2009, unrecognized compensation cost related to nonvested goal-based stock awards totaled approximately $8 million and is expected to be recognized over a weighted-average period of 1.7 years.

Cash-Based Performance Grant

The actual payout of our cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.

The targeted amount of the cash-based performance grant made to officers in April 2007 was $11 million, but the actual payout of the award in February 2009 determined by the Compensation, Governance and Nominating Committee was $16 million, based on the level of performance metrics achieved. At December 31, 2008, a liability of $16 million had been accrued for this award.

In April 2008, a cash-based performance grant was made to officers. Payout of the performance grant will occur by March 15, 2010 and is based on the achievement of three performance metrics during 2008 and 2009: return on invested capital, book value per share and total shareholder return relative to that of a peer group of companies. At June 30, 2009, the targeted amount of the grant was $12 million and a liability of $9 million had been accrued for this award.

In February 2009, a cash-based performance grant was made to officers. Payout of the performance grant will occur by March 15, 2011 and is based on the achievement of three performance metrics during 2009 and 2010: return on invested capital, book value per share and total shareholder return relative to that of a peer group of companies. At June 30, 2009, the targeted amount of the grant was $11 million and a liability of $3 million had been accrued for this award.

Note 18. Commitments and Contingencies

Other than the following matters, there have been no significant developments regarding the commitments and contingencies disclosed in Note 23 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008, or Note 15 to the Consolidated Financial Statements in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, nor have any significant new matters arisen during the three months ended June 30, 2009.

Electric Regulation in Virginia

2007 Virginia Regulation Act

Pursuant to the Virginia Electric Utility Regulation Act (the Regulation Act), the Virginia Commission entered an order in January 2009 initiating reviews of the base rates and terms and conditions of all investor-owned electric utilities in Virginia. Possible outcomes of the 2009 rate review, according to the Regulation Act, include a rate increase, a rate decrease, or a partial refund of 2008 earnings more than 50 basis points above the authorized return on equity (ROE).

In March 2009, we submitted our base rate filing and accompanying schedules to the Virginia Commission. Our filing proposed to increase our Virginia jurisdictional base rates by approximately $298 million annually. We also proposed a 12.5% ROE, plus an additional 100 basis point performance incentive pursuant to the Regulation Act based on our generating plant performance, customer service, and operating efficiency, resulting in a total ROE request of 13.5%. In April 2009, we submitted a revised filing that corrected certain plant balances. The corrected plant balances and related adjustments reduced the increase in our annual requirement by approximately $9 million, to $289 million. We proposed that the base rate increase become effective on an interim basis on September 1, 2009,

PAGE 25

subject to refund and adjustment by the Virginia Commission. In July 2009, in response to rulings by the Virginia Commission relating to the appropriate rate year and capital structure to be used in the Company’s base rate review, we submitted a revised filing that further reduced the increase in our annual revenue requirement approximately $39 million, to $250 million. The proposed rate increase would increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $5.22 per month. The amended filing reflects an upward adjustment of 50 basis points in the proposed ROE. An evidentiary hearing on our base rate filing will be held in January 2010.

In March 2009, we filed with the Virginia Commission, pursuant to the Regulation Act, a petition to recover from Virginia jurisdictional customers an annual net increase of approximately $78 million in costs related to FERC-approved transmission charges and PJM demand response programs. This amount also included a portion of costs discussed further in the RTO Start-up Costs and Administrative Fees section. In a final order in June 2009, the Virginia Commission approved a new rate adjustment clause (Rider T) to recover approximately $218 million over the 12-month period beginning September 1, 2009, subject to an annual review and re-set in 2010, if necessary. The approved amount to be recovered through Rider T includes approximately $150 million of transmission-related costs that were traditionally incorporated in base rates, plus an incremental increase of approximately $68 million. The Virginia Commission also ruled that approximately $10 million that the Company had proposed to collect in Rider T would be more appropriately recovered through base rates, and those costs have been incorporated into the Company’s revised base rate filing that was submitted in July 2009. Once implemented, Rider T is expected to increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $1.11 per month.

In July 2009, we filed with the Virginia Commission an application for approval and cost recovery of twelve demand-side management (DSM) programs, including one peak-shaving program and eleven energy efficiency programs. We plan to use DSM, along with our traditional supply-side resources, to meet our projected load growth over the next 15 years. The DSM programs will also help to achieve Virginia’s goal of reducing, by 2022, the electric energy consumption of the Company’s retail customers by ten percent of what was consumed in 2006. Our application requests approval of the DSM programs by February 1, 2010 and two associated rate adjustment clauses for cost recovery to be effective April 1, 2010, although the Regulation Act gives the Virginia Commission until the end of March 2010 to act on our application. In the filing, we requested approval of the two rate adjustment clauses to recover from Virginia jurisdictional customers an annual net increase of approximately $51 million for the period April 1, 2010 to March 31, 2011. If approved by the Virginia Commission, the rate adjustment clauses will be expected, on a combined basis, to increase a typical 1,000 kWh residential bill by approximately $0.95 per month.

Virginia Fuel Expenses

In March 2009, we filed our Virginia fuel factor application with the Virginia Commission. The application requested an annual decrease in fuel expense recovery of approximately $236 million for the period July 1, 2009 through June 30, 2010, a decrease from 3.893 cents per kWh to 3.529 cents per kWh, or approximately $3.64 per month for the typical 1,000 kWh Virginia jurisdictional residential customer’s average bill. The proposed fuel factor went into effect on July 1, 2009 on an interim basis and an evidentiary hearing on the Company’s application was to be held on July 16, 2009. In a subsequent order, the Virginia Commission postponed the July 16^th hearing until September 1, 2009.

Utility Generation Expansion

In March 2009, we filed with the Virginia Commission our first annual update to the rate adjustment clause for the Virginia City Hybrid Energy Center requesting an increase of approximately $99 million for financing costs to be recovered through rates in 2010. As part of this filing we requested that the 13.5% ROE proposed in our March 31, 2009 base rate filing be applied to the Virginia City Hybrid Energy Center rate adjustment clause (Rider S), plus the 100 basis point enhancement for construction of a new coal-fired generation facility as previously authorized by the Virginia Commission pursuant to the Regulation Act, for a requested total ROE of 14.5%. If approved by the Virginia Commission, the revised Rider S could become effective as early as January 1, 2010 as requested by the Company and would increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $1.78 per month. An evidentiary hearing has been scheduled before a hearing examiner in August 2009.

In March 2009, the Virginia Commission authorized construction and operation of our proposed Bear Garden facility, a 580 MW (nominal) natural gas- and oil-fired combined-cycle electric generating facility and associated transmission interconnection facilities in Buckingham County, Virginia, estimated to cost $619 million, excluding financing costs. In March 2009, we also filed a petition with the Virginia Commission for the initiation of a rate adjustment clause for recovery of approximately $77 million in financing costs related to the construction of the Bear Garden facility to be recovered through rates in 2010. As part of this filing we requested that the 13.5% ROE

PAGE 26

proposed in our March 31, 2009 base rate filing be applied to the Bear Garden facility rate adjustment clause, with a 100 basis point enhancement for construction of a combined-cycle facility, as authorized by the Regulation Act, for a requested total ROE of 14.5%. If approved by the Virginia Commission, the rate adjustment clause could become effective as early as January 1, 2010 as requested by the Company, and would increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $1.40 per month. An evidentiary hearing has been scheduled before a hearing examiner in August 2009.

We are unable to predict the outcome of the Virginia Commission’s future rate actions, including actions relating to our 2009 base rate review, our DSM program, our recovery of Virginia fuel expenses, and our additional rate adjustment clause filings; however, unfavorable future decisions by the Virginia Commission could adversely affect our results of operations, financial condition and cash flows.

RTO Start-up Costs and Administrative Fees

In December 2008, FERC approved our DRC request to become effective January 1, 2009, which allows recovery of approximately $153 million of RTO costs that are being deferred due to a statutory base rate cap established under Virginia law. In June 2009, the Virginia Commission approved full recovery of the DRC from retail customers through Rider T. Recovery of the DRC will begin September 1, 2009. In July 2009, FERC issued an order denying requests for rehearing of its December 2008 order. The time to appeal FERC’s orders has not yet expired. We cannot predict the status or outcome of a potential appeal, if any, of FERC’s orders.

Environmental Matters

In February 2008, we received a request for information pursuant to Section 114 of the Clean Air Act from the EPA. The request concerns historical operating changes and capital improvements undertaken at our State Line and Kincaid power stations. In April 2009, we received a second request for information. We provided information in response to the first request and are in the process of gathering and compiling the information needed to respond to the second request. Also in April 2009, we received a Notice and Finding of Violations from the EPA claiming new source review violations, new source performance standards violations, and Title V permit program violations pursuant to the Clean Air Act and the respective State Implementation Plans. We are evaluating the impact of the Notice and cannot estimate the financial impact of any adverse outcome at this time.

Guarantees

At June 30, 2009, we had issued $416 million of guarantees to support third parties and equity method investees (issued guarantees). This includes $186 million of guarantees to support our investment in a joint venture with Shell WindEnergy Inc. (Shell), which owns a wind-turbine facility in Grant County, West Virginia (NedPower). These NedPower guarantees are primarily comprised of a limited-scope guarantee and indemnification for one-half of the project-level financing for phases one and two of the NedPower wind farm, which would require us to pay one-half of NedPower’s debt, only if it is unable to do so, as a direct result of an unfavorable ruling associated with current litigation seeking to halt the project. This litigation-related guarantee will terminate upon receipt of a final non-appealable ruling in favor of the project. We do not expect an unfavorable ruling and no significant amounts have been recorded. Our exposure under this litigation-related guarantee totaled $159 million as of June 30, 2009. Shell has provided an identical guarantee for the other one-half of NedPower’s borrowings.

Issued guarantees also include $176 million of guarantees to support our investment in a joint venture with BP Alternative Energy (BP) to develop a wind-turbine facility in Benton County, Indiana, referred to as the Fowler Ridge wind farm. The guarantees primarily relate to payments for wind turbines and construction costs. Our exposure under these guarantees was $23 million as of June 30, 2009 and will largely decline during 2009, as the joint venture makes the underlying payments covered by these guarantees. BP has provided identical guarantees for the other one-half of these joint venture commitments. The first phase of the project (300 MW) achieved full commercial operations in March 2009. In June 2009, we reached an agreement with BP to split the development assets of the final 350 MW phase. We will own 150 MW of development assets and BP will retain the remaining development assets. Each entity will develop its own wind facility. Pending regulatory and other approvals, the transaction is expected to close in the fourth quarter of 2009.

PAGE 27

We also enter into guarantee arrangements on behalf of our consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of our consolidated subsidiaries, that liability is included in our Consolidated Financial Statements. We are not required to recognize liabilities for guarantees issued on behalf of our subsidiaries unless it becomes probable that we will have to perform under the guarantees. We believe it is unlikely that we would be required to perform or otherwise incur any losses associated with guarantees of our subsidiaries’ obligations. At June 30, 2009, we had issued the following subsidiary guarantees:


	Stated Limit		Value⁽¹⁾
(millions)
Subsidiary debt⁽²⁾	$	126	$	126
Commodity transactions⁽³⁾		2,533		225
Lease obligation for power generation facility⁽⁴⁾		837		837
Nuclear obligations⁽⁵⁾		513		373
Other		313		139

Total	$	4,322	$	1,700

(1)

Represents the estimated portion of the guarantee’s stated limit that is utilized as of June 30, 2009 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by our subsidiaries, the value includes the recorded amount.

(2)	Guarantees of debt of certain Dominion Energy, Inc. (DEI) subsidiaries. In the event of default by the subsidiaries, we would be obligated to repay such amounts.

(3)

Guarantees related to energy trading and marketing activities and other commodity commitments of certain subsidiaries. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, oil, electricity, pipeline capacity, transportation and other energy-related commodities and services. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, we would be obligated to satisfy such obligation. We and our subsidiaries receive similar guarantees as collateral for credit extended to others. The value provided includes certain guarantees that do not have stated limits.

(4)	Guarantee of a DEI subsidiary’s leasing obligation for Fairless power station.

(5)

Guarantees related to certain DEI subsidiaries’ potential retrospective premiums that could be assessed if there is a nuclear incident under our nuclear insurance programs and guarantees for a DEI subsidiary’s and Virginia Power’s commitments to buy nuclear fuel. Excludes our agreement to provide up to $150 million and $60 million to two DEI subsidiaries, to pay the operating expenses of Millstone power station (Millstone) and Kewaunee power station (Kewaunee), respectively, in the event of a prolonged outage, as part of satisfying certain Nuclear Regulatory Commission (NRC) requirements concerned with ensuring adequate funding for the operations of nuclear power stations.

Surety Bonds and Letters of Credit

As of June 30, 2009, we had purchased $151 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $403 million to facilitate commercial transactions by our subsidiaries with third parties.

Note 19. Credit Risk

Credit risk is our risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We believe, based on our credit policies and our June 30, 2009 provision for credit losses, that it is unlikely a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

As a diversified energy company, we transact primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. and in Texas. We do not believe that this geographic concentration contributes significantly to our overall exposure to credit risk. In addition, as a result of our large and diverse customer base, we are not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations, including transmission services and retail energy sales.

Our exposure to credit risk is concentrated primarily within our energy marketing and price risk management activities, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include trading of energy-related commodities, marketing of merchant generation output, structured transactions and

PAGE 28

the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At June 30, 2009, our gross credit exposure totaled $1.3 billion. After the application of collateral, our credit exposure was reduced to $869 million. Of this amount, investment grade counterparties, including those internally rated, represented 97%. Two counterparty exposures are greater than 10% of our total exposure, one representing 28% and the other 11%, both of which are large financial institutions rated investment grade.

The majority of our derivative instruments contain credit-related contingent provisions. These provisions require us to provide collateral upon the occurrence of specific events, primarily a credit downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of June 30, 2009, we would be required to post an additional $42 million of collateral to our counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. As of June 30, 2009, we have posted $125 million in collateral, including $109 million of letters of credit, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of June 30, 2009 is $174 million and does not include the impact of any offsetting asset positions. See Note 10 for further information about our derivative instruments.

Note 20. Employee Benefit Plans

The components of the provision for net periodic benefit cost (credit) were as follows:


	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008
(millions)
Three Months Ended June 30,
Service cost	$	27		$	25		$	15		$	17
Interest cost		62			57			25			27
Expected return on plan assets		(102	)		(100	)		(14	)		(22	)
Amortization of prior service cost (credit)		1			1			(2	)		(2	)
Amortization of net loss		10			2			8			3
Benefit enhancement		2			—			—			—
Curtailments		2			—			—			—

Net periodic benefit cost (credit)	$	2		$	(15	)	$	32		$	23

Six Months Ended June 30,
Service cost	$	53		$	52		$	30		$	30
Interest cost		125			121			50			47
Expected return on plan assets		(203	)		(211	)		(28	)		(38	)
Amortization of prior service cost (credit)		2			2			(4	)		(3	)
Amortization of net loss		19			4			15			4
Benefit enhancement		2			—			—			—
Curtailments		2			—			—			—

Net periodic benefit cost (credit)	$	—		$	(32	)	$	63		$	40

PAGE 29

Employer Contributions

Under our funding policies, we evaluate pension and other postretirement benefit plan funding requirements annually, usually in the second half of the year after receiving updated plan information from our actuary. Based on the funded status of each plan and other factors, the amount of additional contributions to be made each year, if any, is determined at that time. We made no contributions to our defined benefit pension plans or other postretirement benefit plans during the six months ended June 30, 2009. No contributions to our pension plans are currently expected in 2009, but we do expect to contribute approximately $61 million to our other postretirement benefit plans through Voluntary Employees’ Beneficiary Associations (VEBAs) during the remainder of 2009.

Note 21. Operating Segments

We are organized primarily on the basis of the products and services we sell. We manage our daily operations through the following segments.

DVP includes our regulated electric transmission, distribution and customer service operations, as well as our nonregulated retail energy marketing operations.

Dominion Energy includes our Ohio regulated natural gas distribution company, regulated gas transmission pipeline and storage operations, including gathering and extraction activities, regulated LNG operations and our Appalachian E&P operations. Dominion Energy also includes producer services, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates.

Dominion Generation includes the electric generation operations of our utility and merchant fleet, as well as energy marketing and price risk management activities associated with our generation assets.

Corporate and Other includes our corporate, service company and other functions (including unallocated debt). This segment also includes our regulated gas distribution subsidiaries that are held for sale. In addition, the contribution to net income by our primary operating segments is determined based on a measure of profit that executive management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments and are instead reported in the Corporate and Other segment. In the six months ended June 30, 2009 and 2008, our Corporate and Other segment included $272 million and $27 million, respectively, of after-tax expenses attributable to our operating segments.

•

The expenses in 2009 primarily reflect:

•

A $455 million ($281 million after-tax) ceiling test impairment charge related to the carrying value of our E&P properties, attributable to Dominion Energy; and

•

A $64 million ($38 million after-tax) net loss on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation; partially offset by

•

A $103 million ($62 million after-tax) reduction in other operations and maintenance expense due to a downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service, attributable to Dominion Generation.

•

The expenses in 2008 primarily reflect $51 million ($31 million after-tax) of impairment charges resulting from other-than-temporary declines in the fair value of securities held in nuclear decommissioning trust funds, attributable to Dominion Generation.

Intersegment sales and transfers are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation.

PAGE 30

The following table presents segment information pertaining to our operations:


	DVP		Dominion Energy		Dominion Generation		Corporate and Other			Adjustments/ Eliminations			Consolidated Total
(millions)
Three Months Ended June 30,
2009
Total revenue from external customers	$	660	$	435	$	2,019	$	80		$	256		$	3,450
Intersegment revenue		20		331		95		161			(607	)		—

Total operating revenue		680		766		2,114		241			(351	)		3,450
Net income (loss) attributable to Dominion		82		104		270		(2	)		—			454

2008
Total revenue from external customers	$	636	$	324	$	1,897	$	88		$	454		$	3,399
Intersegment revenue		20		521		31		154			(726	)		—

Total operating revenue		656		845		1,928		242			(272	)		3,399
Loss from discontinued operations, net of tax		—		—		—		(2	)		—			(2	)

Net income (loss) attributable to Dominion		76		70		206		(54	)		—			298

Six Months Ended June 30,
2009
Total revenue from external customers	$	1,649	$	1,382	$	4,281	$	370		$	546		$	8,228
Intersegment revenue		83		652		161		347			(1,243	)		—

Total operating revenue		1,732		2,034		4,442		717			(697	)		8,228
Net income (loss) attributable to Dominion		197		276		639		(410	)		—			702

2008
Total revenue from external customers	$	1,565	$	1,222	$	3,829	$	403		$	733		$	7,752
Intersegment revenue		90		873		47		312			(1,322	)		—

Total operating revenue		1,655		2,095		3,876		715			(589	)		7,752
Loss from discontinued operations, net of tax		—		—		—		(2	)		—			(2	)

Net income (loss) attributable to Dominion		194		252		542		(10	)		—			978

PAGE 31

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MD&A discusses our results of operations and general financial condition. MD&A should be read in conjunction with our Consolidated Financial Statements. The terms “Dominion,” “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

Contents of MD&A

Our MD&A consists of the following information:

•

Forward-Looking Statements

•

Accounting Matters

•

Results of Operations

•

Segment Results of Operations

•

Selected Information — Energy Trading Activities

•

Liquidity and Capital Resources

•

Future Issues and Other Matters

Forward-Looking Statements

This report contains statements concerning our expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “target” or other similar words.

We make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:

•

Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;

•

Extreme weather events, including hurricanes, high winds and winter storms, that can cause outages and property damage to our facilities;

•

State and federal legislative and regulatory developments and changes to environmental and other laws and regulations, including those related to climate change, greenhouse gases and other emissions, to which we are subject;

•

Cost of environmental compliance, including those costs related to climate change;

•

Risks associated with the operation of nuclear facilities;

•

Fluctuations in energy-related commodity prices and the effect these could have on our earnings, liquidity position and the underlying value of our assets;

•

Counterparty credit risk;

•

Capital market conditions, including the availability of credit and our ability to obtain financing on reasonable terms;

•

Price risk due to marketable securities held as investments in nuclear decommissioning and benefit plan trusts;

•

Fluctuations in interest rates;

•

Changes in federal and state tax laws and regulations;

•

Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;

•

Changes in financial or regulatory accounting principles or policies imposed by governing bodies;

•

Employee workforce factors including collective bargaining agreements and labor negotiations with union employees;

•

The risks of operating businesses in regulated industries that are subject to changing regulatory structures;

•

Receipt of approvals for and timing of closing dates for acquisitions and divestitures;

•

Changes in rules for RTOs in which we participate, including changes in rate designs and new and evolving capacity models;

PAGE 32

•

Political and economic conditions, including the threat of domestic terrorism, inflation and deflation;

•

Changes to rates for our regulated electric utility operations, including the outcome of our 2009 rate filings;

•

Timing and receipt of regulatory approvals necessary for planned construction or expansion projects;

•

The inability to complete planned construction or expansion projects within the terms and time frames initially anticipated;

•

Completing the divestiture of Peoples and Hope; and

•

Adverse outcomes in litigation matters.

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2008.

Our forward-looking statements are based on our beliefs and assumptions using information available at the time the statements are made. We caution the reader not to place undue reliance on our forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. We undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

Accounting Matters

Critical Accounting Policies and Estimates

As of June 30, 2009, there have been no significant changes with regard to the critical accounting policies and estimates disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2008, other than the impact of updated nuclear decommissioning cost studies on our AROs as discussed in Note 13 to our Consolidated Financial Statements. The policies disclosed included the accounting for derivative contracts and other instruments at fair value, goodwill and long-lived asset impairment testing, regulated operations, asset retirement obligations, employee benefit plans, gas and oil operations, and income taxes.

Other

See Note 3 to our Consolidated Financial Statements for a discussion of newly adopted accounting standards. See Note 9 to our Consolidated Financial Statements for information on our fair value measurements.

Results of Operations

Presented below is a summary of our consolidated results:


	2009		2008		$ Change
(millions, except EPS)
Second Quarter
Net income attributable to Dominion	$	454	$	298	$	156
Diluted EPS		0.76		0.51		0.25

Year-to-Date
Net income attributable to Dominion	$	702	$	978	$	(276	)
Diluted EPS		1.19		1.69		(0.50	)

Overview

Second Quarter 2009 vs. 2008

Net income attributable to Dominion increased by 52%. Favorable drivers include a benefit from a downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service, higher margins in our merchant generation operations, a benefit from fewer scheduled outages at certain nuclear and fossil generating facilities and a higher contribution from our gas transmission operations due to the completion of the Cove Point expansion project. Unfavorable drivers include the absence of the net benefit recorded in 2008 related to the re-establishment of a regulatory asset in connection with the planned sale of Peoples and Hope and a decrease in sales of gas and oil production from our E&P operations primarily reflecting the expiration of fixed-term overriding royalty interests associated with our former volumetric production payment (VPP) agreements.

Year-to-Date 2009 vs. 2008

Net income attributable to Dominion decreased by 28%. Unfavorable drivers include an impairment charge related to the carrying value of our E&P properties due to declines in gas and oil prices and the absence of benefits

PAGE 33

recognized in 2008 from the reversal of deferred tax liabilities and re-establishment of a regulatory asset associated with the planned sale of Peoples and Hope. Favorable drivers include a benefit from a downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service, higher margins in our merchant generation operations, a benefit from fewer scheduled outages at certain nuclear and fossil generating facilities and a higher contribution from our gas transmission operations due to the completion of the Cove Point expansion project.

Analysis of Consolidated Operations

Presented below are selected amounts related to our results of operations.


	Second Quarter								Year-to-Date
	2009		2008			$ Change			2009		2008			$ Change
(millions)
Operating Revenue	$	3,450	$	3,399		$	51		$	8,228	$	7,752		$	476
Operating Expenses
Electric fuel and other energy-related purchases		998		786			212			2,139		1,567			572
Purchased electric capacity		105		97			8			213		204			9
Purchased gas		368		635			(267	)		1,506		1,790			(284	)
Other operations and maintenance		697		804			(107	)		1,947		1,647			300
Depreciation, depletion and amortization		271		257			14			550		511			39
Other taxes		109		109			—			266		263			3
Other income (loss)		70		(1	)		71			4		(4	)		8
Interest and related charges		221		206			15			441		421			20
Income tax expense		293		200			93			460		357			103

An analysis of our results of operations follows:

Second Quarter 2009 vs. 2008

Operating Revenue increased 2%, primarily reflecting:

•

A $134 million increase in revenue from our electric utility operations resulting primarily from:

•

A $198 million increase in fuel revenue largely due to the impact of a comparatively higher fuel rate in certain customer jurisdictions, including the recovery of previously deferred fuel expenses; and

•

A $21 million increase due to the impact of a rate adjustment clause associated with the recovery of financing costs for the Virginia City Hybrid Energy Center; partially offset by

•

A $54 million decrease in sales to wholesale customers due to decreased volumes ($29 million) and lower prices ($25 million);

•

A $17 million decrease in base revenues from sales to retail customers due to an 8% decrease in cooling degree days partially offset by a 12% increase in heating degree days; and

•

A $9 million decrease in base revenues reflecting the impact of unfavorable economic conditions on customer usage and other factors.

•

A $102 million increase in electricity sales by our retail energy marketing operations primarily due to the acquisition of a retail energy marketing business in September 2008 ($70 million) and higher sales volumes ($40 million), partially offset by lower sales prices ($8 million);

•

A $58 million increase for merchant generation operations largely due to the net impact of higher overall volumes resulting primarily from fewer scheduled nuclear refueling outages and higher demand for natural gas generation ($118 million), partially offset by lower realized prices at certain fossil generating facilities ($60 million); and

•

A $46 million increase related to our gas transmission operations largely due to the completion of the Cove Point expansion project.

These increases were partially offset by:

•

A $135 million decrease in our producer services business primarily due to a decrease in prices ($193 million), partially offset by favorable price changes on economic hedging positions ($58 million), both associated with natural gas aggregation, marketing and trading activities;

•

A $97 million decrease in regulated gas sales by our gas distribution operations reflecting:

•

A $66 million decrease resulting largely from the migration of customers to energy choice programs primarily due to Dominion East Ohio’s exit from the gas merchant function for the majority of its customers; and

•

A $31 million decrease reflecting lower gas prices; and

•

A $54 million decrease in gas sales by our retail energy marketing operations primarily due to lower prices.

PAGE 34

Operating Expenses and Other Items

Electric fuel and other energy-related purchases expense increased 27%, primarily reflecting the combined effects of:

•

A $185 million increase for our utility generation operations primarily reflecting a comparatively higher fuel rate in certain customer jurisdictions, including recovery of previously deferred fuel expenses ($188 million) and a reduced benefit from FTRs ($38 million), partially offset by a decrease in fuel expenses associated with wholesale customers ($41 million); and

•

A $71 million increase from our retail energy marketing operations primarily due to increased energy purchases resulting from the acquisition of a retail energy marketing business; partially offset by

•

A $25 million decrease for our merchant generation operations reflecting lower commodity prices ($61 million), partially offset by increased consumption ($36 million) at certain fossil generating facilities.

Purchased gas expense decreased 42%, principally resulting from the following factors:

•

A $134 million decrease in our producer services business primarily due to the net impact of a decrease in prices ($203 million), partially offset by unfavorable price changes on economic hedging positions ($61 million) and an increase in volumes ($8 million), all associated with natural gas aggregation and marketing activities;

•

A $64 million decrease in the cost of gas sold by our gas distribution operations primarily reflecting lower prices; and

•

A $48 million decrease in our retail energy marketing activities primarily due to lower prices.

Other operations and maintenance expense decreased 13%, primarily reflecting the combined effects of the following:

•

A $103 million downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service; and

•

Fewer scheduled outages at certain nuclear and fossil generating facilities ($77 million); partially offset by

•

The absence of the net benefit recorded in 2008 related to the re-establishment of a regulatory asset in connection with the planned sale of Peoples and Hope ($47 million); and

•

A $32 million increase in salaries, wages and benefits largely due to higher pension and other postretirement benefit costs.

DD&A increased 5%, principally due to higher depreciation from property additions ($30 million), partially offset by decreased DD&A reflecting a decrease in DD&A rates ($9 million) and lower gas and oil production ($6 million) at our E&P properties.

Other income (loss) was income of $70 million as compared to a loss of $1 million in 2008, primarily due to higher nuclear decommissioning trust earnings ($44 million) and an increase in earnings from our equity method investments ($17 million).

Interest and related charges increased 7%, primarily due to an increase in outstanding long-term debt ($30 million), partially offset by a decrease in commercial paper borrowings ($19 million).

Income tax expense increased 47%, reflecting higher pretax income.

Year-to-Date 2009 vs. 2008

Operating Revenue increased 6%, primarily reflecting:

•

A $462 million increase in revenue from our electric utility operations resulting primarily from:

•

A $500 million increase in fuel revenue largely due to the impact of a comparatively higher fuel rate in certain customer jurisdictions, including the recovery of previously deferred fuel expenses;

•

A $53 million increase in base revenues from sales to retail customers due to a 19% increase in heating degree days partially offset by an 8% decrease in cooling degree days; and

•

A $43 million increase due to the impact of a rate adjustment clause associated with the recovery of financing costs for the Virginia City Hybrid Energy Center; partially offset by

•

An $84 million decrease in sales to wholesale customers due to lower prices ($48 million) and decreased volumes ($36 million); and

•

A $48 million decrease in base revenues reflecting the impact of unfavorable economic conditions on customer usage and other factors.

PAGE 35

•

A $168 million increase in electricity sales by our retail energy marketing operations primarily due to the acquisition of a retail energy marketing business in September 2008 ($130 million) and higher sales volumes ($44 million), partially offset by lower sales prices ($6 million);

•

A $131 million increase for merchant generation operations largely due to the net impact of higher overall volumes resulting primarily from fewer scheduled nuclear refueling outages and higher demand for natural gas generation ($191 million), partially offset by lower realized prices at certain fossil generating facilities ($60 million);

•

A $55 million increase in gas transportation and storage revenue resulting principally from higher customer charges at our gas distribution operations due to the implementation of a Straight Fixed Variable rate design and customer migration at Dominion East Ohio;

•

A $54 million increase related to our gas transmission operations largely due to the completion of the Cove Point expansion project; and

•

A $33 million increase in nonregulated gas sales by our gas distribution operations resulting largely from an increase in volumes.

These increases were partially offset by:

•

A $184 million decrease in regulated gas sales by our gas distribution operations reflecting the combined effects of:

•

A $142 million decrease resulting from customer migration; and

•

A $59 million decrease reflecting lower gas prices; partially offset by

•

A $17 million increase in volumes due to the net impact of colder weather during the first quarter, changes in customer usage patterns and other factors;

•

A $97 million decrease in our producer services business primarily due to the net impact of a decrease in prices ($264 million), partially offset by favorable price changes on economic hedging positions ($154 million) and an increase in volumes ($13 million), all associated with natural gas aggregation, marketing and trading activities;

•

A $45 million decrease in gas sales by our retail energy marketing operations primarily due to lower prices; and

•

A $30 million decrease in sales of gas production from our E&P operations primarily reflecting the expiration of fixed-term overriding royalty interests associated with our former VPP agreements.

Operating Expenses and Other Items

Electric fuel and other energy-related purchases expense increased 37%, primarily reflecting the combined effects of:

•

A $482 million increase for our utility generation operations primarily reflecting a comparatively higher fuel rate in certain customer jurisdictions, including recovery of previously deferred fuel expenses ($490 million) and a reduced benefit from FTRs ($43 million), partially offset by a decrease in fuel expenses associated with wholesale customers ($51 million); and

•

A $115 million increase from our retail energy marketing operations primarily due to increased energy purchases resulting from the acquisition of a retail energy marketing business.

Purchased gas expense decreased 16%, principally resulting from the following factors:

•

A $146 million decrease in our producer services business primarily due to the net impact of a decrease in prices ($279 million), partially offset by unfavorable price changes on economic hedging positions ($99 million) and an increase in volumes ($34 million), all associated with natural gas aggregation and marketing activities;

•

An $82 million decrease in the cost of gas sold by our gas distribution operations primarily reflecting lower prices;

•

A $32 million decrease in our gas transmission operations primarily due to lower prices; and

•

A $20 million decrease in our retail energy marketing activities primarily due to lower prices.

Other operations and maintenance expense increased 18%, primarily reflecting the combined effects of:

•

A $455 million ceiling test impairment charge related to the carrying value of our E&P properties due to declines in natural gas and oil prices;

•

A $65 million increase in salaries, wages and benefits largely due to higher pension and other postretirement benefit costs; and

•

The absence of the net benefit recorded in 2008 related to the re-establishment of a regulatory asset in connection with the planned sale of Peoples and Hope ($47 million); partially offset by

PAGE 36

•

A $103 million downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service;

•

Fewer scheduled outages at certain nuclear and fossil generating facilities ($81 million); and

•

The absence of a $62 million charge related to the impairment of a DCI investment sold in 2008.

DD&A increased 8%, principally due to higher depreciation from property additions ($55 million) and higher amortization due to increased consumption of emissions allowances ($15 million), partially offset by decreased DD&A reflecting lower gas and oil production ($13 million) and a decrease in DD&A rates ($9 million) at our E&P properties.

Interest and related charges increased 5%, primarily due to an increase in outstanding long-term debt ($59 million), partially offset by a decrease in commercial paper borrowings ($37 million).

Income tax expense increased by 29% although pre-tax income decreased by 13%, largely due to the absence of the benefit from the reversal of deferred tax liabilities in the first quarter of 2008, associated with a change in the expected tax treatment of the planned sale of Peoples and Hope.

Segment Results of Operations

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit and loss. Presented below is a summary of contributions by our operating segments to net income attributable to Dominion:


	Net Income attributable to Dominion									Diluted EPS
	2009			2008			$ Change			2009			2008			$ Change
(millions, except EPS)
Second Quarter
DVP	$	82		$	76		$	6		$	0.14		$	0.13		$	0.01
Dominion Energy		104			70			34			0.17			0.12			0.05
Dominion Generation		270			206			64			0.46			0.36			0.10

Primary operating segments		456			352			104			0.77			0.61			0.16
Corporate and Other		(2	)		(54	)		52			(0.01	)		(0.10	)		0.09

Consolidated	$	454		$	298		$	156		$	0.76		$	0.51		$	0.25

Year-to-Date
DVP	$	197		$	194		$	3		$	0.33		$	0.34		$	(0.01	)
Dominion Energy		276			252			24			0.47			0.43			0.04
Dominion Generation		639			542			97			1.08			0.94			0.14

Primary operating segments		1,112			988			124			1.88			1.71			0.17
Corporate and Other		(410	)		(10	)		(400	)		(0.69	)		(0.02	)		(0.67	)

Consolidated	$	702		$	978		$	(276	)	$	1.19		$	1.69		$	(0.50	)

DVP

Presented below are selected operating statistics related to DVP’s operations:


	Second Quarter				Year-to-Date
	2009	2008	% Change		2009	2008	% Change
Electricity delivered (million MWh)	19.0	20.0	(5	)%	40.3	40.8	(1	)%
Degree days (electric distribution service area):
Cooling⁽¹⁾	459	501	(8	)	463	504	(8	)
Heating⁽²⁾	294	263	12		2,457	2,072	19
Average electric distribution customer accounts (thousands)⁽³⁾	2,401	2,382	1		2,400	2,381	1
Average retail energy marketing customer accounts (thousands)⁽³⁾	1,725	1,597	8		1,679	1,592	5

(1)	Cooling degree days are units measuring the extent to which the average daily temperature is greater than 65 degrees, and are calculated as the difference between 65 degrees and the average temperature for that day.

(2)	Heating degree days are units measuring the extent to which the average daily temperature is less than 65 degrees, and are calculated as the difference between 65 degrees and the average temperature for that day.

(3)	Period average.

PAGE 37

Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:


	Second Quarter						Year-to-Date
	2009 vs. 2008						2009 vs. 2008
	Increase (Decrease)						Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Storm damage and restoration services⁽¹⁾	$	8		$	0.01		$	8		$	0.01
Regulated electric sales:
Weather		(3	)		(0.01	)		13			0.02
Customer growth		1			—			3			0.01
Other⁽²⁾		(2	)		—			(9	)		(0.02	)
Retail energy marketing operations		(7	)		(0.01	)		(22	)		(0.04	)
Other⁽³⁾		9			0.02			10			0.02
Share dilution		—			—			—			(0.01	)

Change in net income contribution	$	6		$	0.01		$	3		$	(0.01	)

(1)	Reflects lower storm damage and service restoration costs associated with our electric distribution operations.

(2)	Decrease primarily reflects the impact of unfavorable economic conditions on customer usage and other factors.

(3)	Primarily reflects the deferral of transmission-related expenditures collectible under certain rate adjustment clauses.

Dominion Energy

Presented below are selected operating statistics related to our Dominion Energy operations:


	Second Quarter						Year-to-Date
	2009		2008		% Change		2009		2008		% Change
Gas distribution throughput (bcf):
Sales		3		6	(50	)%		24		32	(25	)%
Transportation		31		37	(16	)		115		128	(10	)
Heating degree days (gas distribution service area)		667		703	(5	)		3,818		3,875	(1	)
Average gas distribution customer accounts (thousands)⁽¹⁾:
Sales		180		396	(55	)		257		401	(36	)
Transportation		1,018		810	26			946		810	17
Production⁽²⁾ (bcfe):		12.0		16.0	(25	)		26.4		33.9	(22	)
Average realized prices without hedging results (per mcfe)	$	3.58	$	10.53	(66	)	$	4.37	$	9.14	(52	)
Average realized prices with hedging results (per mcfe)		7.14		8.48	(16	)		7.55		8.65	(13	)
DD&A (unit of production rate per mcfe)		1.39		1.97	(29	)		1.67		1.94	(14	)
Average production (lifting) cost⁽³⁾ (per mcfe)		1.26		1.35	(7	)		1.25		1.27	(2	)

(1)	Period average.

(2)

Includes natural gas, natural gas liquids and oil. Production includes 2.3 bcfe for the year-to-date period ended June 30, 2009, and 4.5 bcfe and 10.8 bcfe for the quarter and year-to-date period ended June 30, 2008 associated with reacquired overriding royalty interests arising from the VPPs terminated in 2007. There was no production related to VPPs for the quarter ended June 30, 2009 due to the expiration of these interests in February 2009.

(3)

The inclusion of volumes associated with reacquired overriding royalty interests arising from the VPPs terminated in 2007 would have resulted in lifting costs of $1.18 for the year-to-date period ended June 30, 2009, and $1.09 and $0.99 for the quarter and year-to-date period ended June 30, 2008, respectively. There were no volumes related to VPPs for the quarter ended June 30, 2009 due to the expiration of these interests in February 2009.

PAGE 38

Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:


	Second Quarter						Year-to-Date
	2009 vs. 2008						2009 vs. 2008
	Increase (Decrease)						Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Cove Point expansion revenue	$	27		$	0.04		$	35		$	0.07
DD&A – gas and oil		9			0.02			13			0.02
Producer services⁽¹⁾		4			0.01			30			0.06
Gas and oil – production⁽²⁾		(19	)		(0.03	)		(38	)		(0.07	)
Change in state tax legislation⁽³⁾		—			—			(16	)		(0.03	)
Other		13			0.02			—			—
Share dilution		—			(0.01	)		—			(0.01	)

Change in net income contribution	$	34		$	0.05		$	24		$	0.04

(1)	Year-to-date increase is largely due to colder than normal weather throughout the mid-Atlantic and Northeast market areas, the utilization of firm transportation and favorable price changes on economic hedging positions.

(2)	Principally due to the expiration of fixed-term overriding royalty interests associated with our former VPP agreements.

(3)	Reflects the absence of a 2008 benefit resulting from the reduction of deferred tax liabilities related to the enactment of West Virginia income tax rate reductions in March 2008.

Included below are the volumes and weighted-average prices associated with hedges in place for our E&P operations as of June 30, 2009, by applicable time period:


	Natural Gas
Year	Hedged Production (bcf)	Average Hedge Price (per mcf)
2009	14.9	$	9.03
2010	22.1		7.94
2011	1.4		7.36

Dominion Generation

Presented below are selected operating statistics related to our Dominion Generation operations:


	Second Quarter				Year-to-Date
	2009	2008	% Change		2009	2008	% Change
Electricity supplied (million MWh):
Utility	19.0	20.0	(5	)%	40.3	40.8	(1	)%
Merchant	12.1	9.7	25		24.7	21.0	18
Degree days (electric utility service area):
Cooling	459	501	(8	)	463	504	(8	)
Heating	294	263	12		2,457	2,072	19

PAGE 39

Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:


	Second Quarter						Year-to-Date
	2009 vs. 2008						2009 vs. 2008
	Increase (Decrease)						Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Merchant generation margin⁽¹⁾	$	66		$	0.11		$	106		$	0.18
Outage costs		48			0.08			51			0.09
Energy supply margin⁽²⁾		(17	)		(0.03	)		(20	)		(0.03	)
Sales of emissions allowances		(10	)		(0.02	)		(17	)		(0.03	)
Depreciation and amortization		(10	)		(0.02	)		(22	)		(0.04	)
Regulated electric sales:
Weather		(8	)		(0.01	)		20			0.03
Customer growth		3			0.01			6			0.01
Rate adjustment clause⁽³⁾		13			0.02			27			0.04
Other⁽⁴⁾		(13	)		(0.02	)		(40	)		(0.07	)
Other		(8	)		(0.01	)		(14	)		(0.02	)
Share dilution		—			(0.01	)		—			(0.02	)

Change in net income contribution	$	64		$	0.10		$	97		$	0.14

(1)	Primarily attributable to higher volumes at certain nuclear and fossil generating facilities.

(2)	Reflects lower settlement gains on FTRs.

(3)	Reflects the impact of a new rate adjustment clause associated with the recovery of financing costs for the Virginia City Hybrid Energy Center.

(4)	Decrease reflects the impact of unfavorable economic conditions on customer usage and other factors, as well as lower sales to wholesale customers.

Corporate and Other

Presented below are the Corporate and Other segment’s after-tax results:


	Second Quarter									Year-to-Date
	2009			2008			$ Change			2009			2008			$ Change
(millions, except EPS)
Specific items attributable to operating segments	$	64		$	(11	)	$	75		$	(272	)	$	(27	)	$	(245	)
Discontinued operations		—			(2	)		2			—			(2	)		2
Peoples and Hope		8			30			(22	)		34			61			(27	)
Other corporate operations		(74	)		(71	)		(3	)		(172	)		(42	)		(130	)

Total net benefit (expense)	$	(2	)	$	(54	)	$	52		$	(410	)	$	(10	)	$	(400	)

EPS impact	$	(0.01	)	$	(0.10	)	$	0.09		$	(0.69	)	$	(0.02	)	$	(0.67	)

Specific Items Attributable to Operating Segments

Corporate and Other includes specific items attributable to our operating segments that have been excluded from profit measures evaluated by management, either in assessing segment performance or in allocating resources among the segments. See Note 21 to our Consolidated Financial Statements for discussion of significant items.

Peoples and Hope

The quarter and year-to-date decrease is primarily due to the absence of the net benefit recorded in 2008 related to the re-establishment of a regulatory asset in connection with the planned sale of these subsidiaries.

PAGE 40

Other Corporate Operations

Year-to-date 2009 vs. 2008

Net expenses increased $130 million, primarily due to the absence of the following 2008 items:

•

The reversal of $136 million of deferred tax liabilities associated with Peoples and Hope; partially offset by

•

A $38 million after-tax impairment charge recorded related to a DCI investment that was subsequently sold in April 2008.

In addition, the impact of annualizing our interim income tax provision, reflecting the estimated annual effective tax rate for our combined segments, increased expenses by $23 million.

Selected Information—Energy Trading Activities

See Selected Information-Energy Trading Activities in MD&A included in our Annual Report on Form 10-K for the year ended December 31, 2008 for a discussion of our energy trading, hedging and marketing activities and related accounting policies. For additional discussion of trading activities, see Market Risk Sensitive Instruments and Risk Management in Item 3.

A summary of the changes in unrealized gains and losses recognized for our energy-related derivative instruments held for trading purposes follows:


	Amount
(millions)
Net unrealized gain at December 31, 2008	$	43
Contracts realized or otherwise settled during the period		(40	)
Net unrealized gain at inception of contracts initiated during the period		—
Change in unrealized gains and losses		10
Changes in unrealized gains and losses attributable to changes in valuation techniques		—

Net unrealized gain at June 30, 2009	$	13

The fair values and categorization summarized below were determined in accordance with the requirements of SFAS No. 157. The balance of net unrealized gains and losses recognized for our energy-related derivative instruments held for trading purposes at June 30, 2009, is summarized in the following table based on the inputs used to determine fair value:


	Maturity Based on Contract Settlement or Delivery Date(s)
Source of Fair Value	Less than 1 year			1-2 years		2-3 years		3-5 years		In excess of 5 years		Total
(millions)
Actively quoted – Level 1⁽¹⁾	$	18		$	3	$	—	$	—	$	—	$	21
Other external sources – Level 2⁽²⁾		(14	)		—		—		—		—		(14	)
Models and other valuation methods – Level 3⁽³⁾		1			2		3		—		—		6

Total	$	5		$	5	$	3	$	—	$	—	$	13

(1)	Values represent observable unadjusted quoted prices for traded instruments in active markets.

(2)	Values with inputs that are observable directly or indirectly for the instrument, but do not qualify for Level 1.

(3)	Values with a significant amount of inputs that are not observable for the instrument.

Liquidity and Capital Resources

We depend on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.

At June 30, 2009, we had $3.8 billion of unused capacity under our credit facilities.

PAGE 41

A summary of our cash flows for the six months ended June 30, 2009 and 2008 is presented below:


	2009			2008
(millions)
Cash and cash equivalents at January 1,⁽¹⁾	$	71		$	287
Cash flows provided by (used in):
Operating activities		1,902			536
Investing activities		(1,788	)		(1,671	)
Financing activities		(119	)		939

Net decrease in cash and cash equivalents		(5	)		(196	)

Cash and cash equivalents at June 30,⁽²⁾	$	66		$	91

(1)	2009 and 2008 amounts include $5 million and $4 million, respectively, of cash classified as held for sale in our Consolidated Balance Sheets.

(2)	2009 and 2008 amounts include $2 million and $3 million, respectively, of cash classified as held for sale in our Consolidated Balance Sheets.

Operating Cash Flows

For the six months ended June 30, 2009, net cash provided by operating activities increased by $1.4 billion as compared to the six months ended June 30, 2008. The increase was due to a positive impact from deferred fuel and gas cost recoveries primarily due to increased fuel revenue and lower fuel costs, higher cash contributions from our merchant generation operations, lower outage costs and lower collateral requirements related to commodity hedging activities, partially offset by higher income tax payments. Our operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows which are discussed in Item 1A. Risk Factors in our Annual Report on Form 10-K for the year-ended December 31, 2008.

Credit Risk

As discussed in Note 19 to our Consolidated Financial Statements, our exposure to potential concentrations of credit risk results primarily from our energy marketing and price risk management activities. Presented below is a summary of our gross credit exposure as of June 30, 2009, for these activities. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights.


	Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade⁽¹⁾	$	1,129	$	404	$	725
Non-investment grade⁽²⁾		9		—		9
No external ratings:
Internally rated—investment grade⁽³⁾		117		—		117
Internally rated—non-investment grade⁽⁴⁾		18		—		18

Total	$	1,273	$	404	$	869

(1)	Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 55% of the total net credit exposure.

(2)	The five largest counterparty exposures, combined, for this category represented approximately 1% of the total net credit exposure.

(3)	The five largest counterparty exposures, combined, for this category represented approximately 9% of the total net credit exposure.

(4)	The five largest counterparty exposures, combined, for this category represented less than 1% of the total net credit exposure.

Investing Cash Flows

For the six months ended June 30, 2009, net cash used in investing activities increased by $117 million as compared to the six months ended June 30, 2008, primarily due to an increase in capital expenditures related to our electric utility operations, partially offset by higher investment in our wind farm facilities in the comparable prior year period.

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Financing Cash Flows and Liquidity

We rely on banks and capital markets as significant sources of funding for capital requirements not satisfied by cash provided by our operations. As discussed further in the Credit Ratings and Debt Covenants section, our ability to borrow funds or issue securities and the return demanded by investors are affected by the issuing company’s credit ratings. In addition, the raising of external capital is subject to meeting certain regulatory requirements, including registration with the SEC and in the case of Virginia Power, approval by the Virginia Commission.

For the six months ended June 30, 2009, net cash used in financing activities was $119 million as compared to net cash provided from financing activities of $939 million in 2008. This change is primarily due to lower net debt issuances, partially offset by increased proceeds from common stock issuances.

See Note 16 to our Consolidated Financial Statements for further information regarding our credit facilities, liquidity and significant financing transactions.

Credit Ratings and Debt Covenants

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In the Credit Ratings section of MD&A in our Annual Report on Form 10-K for the year ended December 31, 2008, we discussed the use of capital markets by Dominion and Virginia Power, as well as the impact of credit ratings on the accessibility and costs of using these markets. As of June 30, 2009, there have been no changes in our credit ratings. In April 2009, Moody’s revised its credit ratings outlook for Virginia Power to positive from stable.

In addition, in the Debt Covenant section of MD&A in our Annual Report on Form 10-K for the year ended December 31, 2008, we discussed various covenants present in the enabling agreements underlying Dominion and Virginia Power’s debt. As of June 30, 2009, there have been no events of default under our debt covenants. In June 2009, we issued $685 million of 8.375% Series A Enhanced Junior Subordinated Notes (hybrids) that will mature in 2064, subject to extensions to no later than 2079. Also in June 2009, we executed a Replacement Capital Covenant (RCC) in connection with the offering of the hybrids. Under the terms of the RCC, we promise and covenant to and for the benefit of designated covered debtholders (as may be designated from time to time, with the initially designated covered debt and the initial covered debtholders being the $400 million Series B 7.0% Senior Notes due 2038 issued in June 2008 and the holders thereof) that we shall not redeem or purchase, or satisfy, discharge or defease (collectively, defease or a defeasance) all or any part of the hybrids, and shall cause our majority owned subsidiaries not to purchase all or any part of the hybrids, on or before June 15, 2034 (which date will be automatically extended as set forth in the RCC for additional quarterly periods to no later than June 15, 2049, if and to the extent that the maturity date of the hybrids is extended), unless, subject to certain limitations, during the 180 days prior to the date of that redemption, purchase or defeasance we have received a specified amount of proceeds as set forth in the RCC from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than, the applicable characteristics of the hybrids at that time, as more fully described in the RCC. For a complete copy of the RCC, refer to our Current Report on Form 8-K filed on June 15, 2009. Other than the RCC discussed above, as of June 30, 2009, there have been no changes to our debt covenants.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

As of June 30, 2009, there have been no material changes outside the ordinary course of business to our contractual obligations nor any material changes to our planned capital expenditures disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2008.

Use of Off-Balance Sheet Arrangements

As of June 30, 2009, there have been no material changes in the off-balance sheet arrangements disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2008.

PAGE 43

Future Issues and Other Matters

The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by and subsequent to our Consolidated Financial Statements. This section should be read in conjunction with Item 1. Business and Future Issues and Other Matters in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2008 and Future Issues and Other Matters in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009. In addition, see Note 18 to our Consolidated Financial Statements and Part II, Item 1. Legal Proceedings for additional information on various environmental, regulatory, legal and other matters that may impact our future results of operations and/or financial condition, including a discussion of electric regulation in Virginia.

Regulatory Approval of Sale of Peoples and Hope

In September 2008, Peoples, Dominion and Peoples Hope Gas Companies LLC (PH Gas) filed a joint petition with the Pennsylvania Commission seeking approval of the purchase by PH Gas of all of the stock of Peoples. In February and March 2009, we made a joint request with PH Gas to the Pennsylvania Commission for a temporary suspension in the sale approval proceeding pending a change in the ownership structure of the Fund. Such proceeding resumed in May 2009, following the SteelRiver Transaction. In October 2008, Hope, Dominion and PH Gas filed a joint petition seeking West Virginia Commission approval of the purchase by PH Gas of all of the stock of Hope. In September 2008, Dominion and the Fund each filed a Premerger Notification and Report Form with the U.S. Department of Justice and the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act). In October 2008, the waiting period under the HSR Act related to the proposed sale of Peoples and Hope to PH Gas expired. The transaction is expected to close in 2009, subject to state regulatory approvals in Pennsylvania and West Virginia.

Wind Power Project

In January 2008, we acquired a 50% interest in a joint venture with BP to develop Fowler Ridge. The first phase consisting of 300 MW achieved full commercial operations in March 2009. We have a long-term agreement with the joint venture to purchase 200 MW of energy, capacity and environmental attributes from this first phase. In June 2009, we reached an agreement with BP to split the development assets of the final 350 MW phase. We will own 150 MW of development assets and BP will retain the remaining development assets. Each entity will develop its wind facility. Pending regulatory and other approvals, the transaction is expected to close in the fourth quarter of 2009. BP has developed an additional 100 MW facility in which Dominion does not have an ownership interest.

North Anna Power Station

In January 2008, the NRC accepted and deemed complete our application for a Combined Construction Permit and Operating License (COL) that references a specific reactor design and which would allow us to build and operate a new nuclear unit at North Anna. In December 2008, we terminated a long-lead agreement with our vendor with respect to the reactor design identified in our COL application and certain related equipment. In March 2009, we commenced a competitive process to determine if vendors can provide an advanced technology reactor that could be licensed and built under terms acceptable to us. If, as a result of this process, we choose a different reactor design, we will amend our COL application, as necessary. We have not yet committed to building a new nuclear unit.

In May 2009, the Department of Energy (DOE) announced the names of four energy companies that have been selected to begin negotiations for federal loan guarantees for proposed new nuclear units in the United States. Although Dominion, in a two-part process, submitted an application for a federal loan guarantee for the proposed North Anna unit, the Company was not among those selected. While we can provide no assurance, because of the dynamic nature of the market for new nuclear units, there may be other opportunities to secure a loan guarantee with the DOE.

Collective Bargaining Agreement

In July 2009, members of the Utility Workers’ Union of America, United Gas Workers’ Local G-555, AFL-CIO (Local G-555) ratified a new three-year contract with Dominion. The new contract runs through June 15, 2012. Local G-555 represents about 1,200 employees in Ohio.

Environmental Matters

We are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

PAGE 44

Clean Water Act Compliance

In October 2007, the Virginia State Water Control Board (Water Board) issued a renewed water discharge (VPDES) permit for North Anna. The Blue Ridge Environmental Defense League, and other persons, appealed the Water Board’s decision to the Richmond Circuit Court, challenging several permit provisions related to North Anna’s discharge of cooling water. In February 2009, the court ruled that the Water Board was required to regulate the thermal discharge from North Anna into the waste heat treatment facility. We filed a motion for reconsideration with the court in February 2009, which was denied. We intend to appeal the court’s decision and ask for a stay of the court’s order. A final order is expected to be issued by the end of August 2009. It is expected that the order will allow North Anna to continue to operate pursuant to the currently issued VPDES permit. Until the final permit is reissued, it is not possible to predict any financial impact that may result.

In October 2003, the EPA and the Massachusetts Department of Environmental Protection each issued new water discharge (NPDES) permits for Brayton Point power station. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. Currently, we estimate the total cost to install these cooling towers at approximately $670 million.

Global Climate Change

In June 2009, the U.S. House of Representatives passed comprehensive legislation titled the “American Clean Energy and Security Act of 2009” to encourage the development of clean energy sources and reduce greenhouse gas (GHG) emissions. The legislation contains provisions establishing federal renewable energy standards for electric suppliers. The legislation also includes cap-and-trade provisions for the reduction of GHG emissions. Similar legislation is currently being considered in the U.S. Senate. The cost of compliance with future GHG emission reduction programs could be significant. Given the highly uncertain outcome and timing of future action by the U.S. federal government and states on this issue, we cannot predict the financial impact of future GHG emission reduction programs on our operations, shareholders or customers at this time.

PAGE 45

ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part I, Item 2. MD&A of this Form 10-Q. The reader’s attention is directed to those paragraphs for discussion of various risks and uncertainties that may affect our future.

Market Risk Sensitive Instruments and Risk Management

Our financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates and equity security prices as described below. Commodity price risk is present in our electric operations, gas production and procurement operations, and energy marketing and trading operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. We use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to our outstanding debt and expected debt issuances. In addition, we are exposed to investment price risk through various portfolios of equity and debt securities.

The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% unfavorable change in commodity prices and interest rates.

Commodity Price Risk

To manage price risk, we primarily hold commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products. As part of our strategy to market energy and to manage related risks, we also hold commodity-based financial derivative instruments for trading purposes.

The derivatives used to manage our commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices of commodity-based financial derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on observable market prices.

A hypothetical 10% unfavorable change in market prices of our non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $176 million and $236 million as of June 30, 2009 and December 31, 2008, respectively. The decline in sensitivity is largely due to a decrease in commodity prices as well as decreased commodity derivative activity. A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $3 million and $5 million in the fair value of our commodity-based financial derivative instruments held for trading purposes as of June 30, 2009 and December 31, 2008, respectively.

The impact of a change in energy commodity prices on our non-trading commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled. Net losses from commodity derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.

Interest Rate Risk

We manage our interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. We may also enter into interest-rate swaps when deemed appropriate to adjust our exposure based upon market conditions. At June 30, 2009 and December 31, 2008, a hypothetical 10% increase in market interest rates would have resulted in a decrease in annual earnings of approximately $2 million and $4 million, respectively.

Additionally, we may use forward-starting interest-rate swaps and treasury rate locks as anticipatory hedges. At June 30, 2009, we had $2 billion in aggregate notional amounts of these interest-rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $72 million in the fair value of these interest-rate derivatives at June 30, 2009. We did not have a significant amount of these interest-rate derivatives outstanding at December 31, 2008.

PAGE 46

The impact of a change in market interest rates on these anticipatory hedges at a point in time is not necessarily representative of the results that will be realized when such contracts are settled. Net losses from interest-rate derivatives used for anticipatory hedging purposes, to the extent realized, will generally be amortized over the life of the respective debt issuance being hedged.

Investment Price Risk

We are subject to investment price risk due to securities held as investments in decommissioning trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in our Consolidated Balance Sheets at fair value.

We recognized net realized losses (net of investment income) on nuclear decommissioning trust investments of $89 million, $38 million and $192 million for the six months ended June 30, 2009 and 2008 and for the year ended December 31, 2008, respectively. Net realized losses include gains and losses from the sale of investments as well as other-than-temporary impairments recognized in earnings. For the six months ended June 30, 2009, we recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $152 million. For the six months ended June 30, 2008 and for the year ended December 31, 2008, we recorded, in AOCI and regulatory liabilities, a reduction in unrealized gains on these investments of $176 million and $451 million, respectively.

We sponsor employee pension and other postretirement benefit plans, in which our employees participate, that hold investments in trusts to fund benefit payments. Investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

ITEM 4. CONTROLS AND PROCEDURES

Senior management, including our CEO and CFO, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, the CEO and CFO have concluded that our disclosure controls and procedures are effective.

There were no changes in our internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PAGE 47

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, we are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by us, or permits issued by various local, state and federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, we are involved in various legal proceedings. We believe that the ultimate resolution of these proceedings will not have a material adverse effect on our financial position, liquidity or results of operations. See Note 18 to our Consolidated Financial Statements and Future Issues and Other Matters in MD&A for discussions on various environmental and other regulatory proceedings to which we are a party.

In February 2009, we received notice from Maryland’s Attorney General’s Office that the Maryland Department of the Environment (MDE) had referred to them, for enforcement, alleged violations of state wetlands, water pollution, and sediment pollution laws during construction of a pipeline associated with the Cove Point expansion project in Maryland. This served notice that MDE would be seeking civil penalties for some of the alleged violations. In May 2009, we received a letter from MDE detailing all alleged violations and their maximum penalty liabilities. The proposed penalty liabilities have not been accepted by the Company and are subject to ongoing negotiations with MDE. Management believes that the ultimate resolution of the proceeding will not have a material effect on the Company.

ITEM 1A. RISK FACTORS

Our business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond our control. We have identified a number of these risk factors in our Annual Report on Form 10-K for the year ended December 31, 2008, which should be taken into consideration when reviewing the information contained in this report. There have been no material changes with regard to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in MD&A.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no unregistered sales of equity securities during the second quarter of 2009.

ISSUER PURCHASES OF EQUITY SECURITIES


Period	(a) Total Number of Shares (or Units) Purchased⁽¹⁾	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs
4/1/09-4/30/09	198,797	$	30.99	N/A	53,971,148 shares/ $2.68 billion
5/1/09-5/31/09	43,500		31.87	N/A	53,971,148 shares/ $2.68 billion
6/1/09-6/30/09	22,498		31.79	N/A	53,971,148 shares/ $2.68 billion
Total	264,795	$	31.20	N/A	53,971,148 shares/ $2.68 billion

(1)	Amount represents registered shares tendered by employees to satisfy tax withholding obligations on vested restricted and goal-based stock.

PAGE 49

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Our Annual Shareholders’ Meeting was held on May 5, 2009. Results of items presented for voting are listed below.

Election of Directors

Directors were elected to the Board of Directors for a one-year term or until next year’s annual meeting.


Nominee	Votes For	Votes Against	Votes Abstained
Peter W. Brown	475,588,870	6,439,797	3,279,830
George A. Davidson, Jr.	462,972,078	19,172,360	3,164,059
Thomas F. Farrell, II	475,261,287	6,878,476	3,168,734
John W. Harris	464,758,963	17,267,103	3,282,431
Robert S. Jepson, Jr.	465,775,363	16,240,877	3,292,257
Mark J. Kington	465,930,923	16,042,482	3,335,092
Benjamin J. Lambert, III	474,143,495	7,807,947	3,357,055
Margaret A. McKenna	476,492,606	5,674,746	3,141,145
Frank S. Royal	464,081,759	17,854,449	3,372,289
David A. Wollard	464,795,488	17,185,571	3,327,438

Appointment of Independent Auditors

The appointment of Deloitte & Touche LLP as our independent auditors for 2009 was ratified by shareholders as follows:


Votes For	Votes Against	Votes Abstained
479,340,611	4,224,551	1,744,278

Amend 2005 Incentive Compensation Plan

Shareholders approved the adoption of the amended and restated 2005 Incentive Compensation Plan. The vote was as follows:


Votes For	Votes Against	Votes Abstained	Broker Non-vote
328,095,564	72,186,463	9,306,546	75,720,867

Shareholder Proposals

Shareholders did not approve a proposal requesting the Company to set and pursue a Company goal to achieve 80% fossil-fuel-free electricity generation by 2020. The vote was as follows:


Votes For	Votes Against	Votes Abstained	Broker Non-vote
14,772,289	328,916,445	65,901,925	75,718,781

Shareholders did not approve a proposal regarding an advisory vote on executive compensation. The vote was as follows:


Votes For	Votes Against	Votes Abstained	Broker Non-vote
174,771,746	229,906,886	4,906,455	75,724,353

Shareholders did not approve a proposal regarding executive supplemental retirement benefits. The vote was as follows:


Votes For	Votes Against	Votes Abstained	Broker Non-vote
107,368,131	296,980,198	5,236,418	75,724,693

PAGE 50

ITEM 6. EXHIBITS

(a) Exhibits:


3.1		Articles of Incorporation as in effect August 9, 1999, as amended March 12, 2001 (Exhibit 3.1, Form 10-K for the year ended December 31, 2002, File No. 1-8489, incorporated by reference), as amended November 9, 2007 (Exhibit 3, Form 8-K, filed November 9, 2007, File No. 1-8489, incorporated by reference).

3.2		Amended and Restated Bylaws effective on June 20, 2007 (Exhibit 3.1, Form 8-K filed June 22, 2007, File No. 1-8489, incorporated by reference).

4.1		Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and the Bank of New York (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006, File No. 1-8489, incorporated by reference), as supplemented by the First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006, File No. 1-8489, incorporated by reference); the Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006, File No. 1-8489, incorporated by reference); and the Third Supplemental and Amending Indenture dated as of June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489, incorporated by reference).

4.2		Form of Replacement Capital Covenant entered into by Dominion Resources, Inc. dated as of June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489, incorporated by reference).

4.3*		Form of Senior Indenture, dated as of June 1, 1998, between Virginia Electric and Power Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by the First Supplemental Indenture (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255, incorporated by reference); Second Supplemental Indenture (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255, incorporated by reference); Third Supplemental Indenture (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255, incorporated by reference); Form of Fourth Supplemental Indenture (Exhibit 4.2, Form 8-K filed March 26, 2001, File No. 1-2255, incorporated by reference); Form of Fifth Supplemental Indenture (Exhibit 4.3, Form 8-K filed March 26, 2001, File No. 1-2255, incorporated by reference); Form of Sixth Supplemental Indenture (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255, incorporated by reference); Seventh Supplemental Indenture (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255, incorporated by reference); Form of Eighth Supplemental Indenture (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255, incorporated by reference); Form of Ninth Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Tenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Eleventh Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255, incorporated by reference); Form of Twelfth Supplemental Indenture (Exhibit 4.2, Form 8-K filed January 12, 2006, File No. 1-2255, incorporated by reference); Form of Thirteenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed January 12, 2006, File No. 1-2255, incorporated by reference); Form of Fourteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255, incorporated by reference); Form of Fifteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255, incorporated by reference); Form of Sixteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed November 30, 2007, File No. 1-2255, incorporated by reference); Form of Seventeenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed November 30, 2007, File No. 1-2255, incorporated by reference); Form of Eighteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255, incorporated by reference); Nineteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255, incorporated by reference); Form of Twentieth Supplemental Indenture (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255, incorporated by reference).

4.4		Dominion Resources, Inc. agrees to furnish to the SEC upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of its total consolidated assets.

10**		Dominion Resources, Inc. 2005 Incentive Compensation Plan, as amended and restated effective May 5, 2009 (Exhibit 10, Form 8-K filed May 11, 2009, File No. 1-8489, incorporated by reference).

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12		Ratio of earnings to fixed charges (filed herewith).

31.1		Certification by Dominion Resources, Inc.’s CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

31.2		Certification by Dominion Resources, Inc.’s CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

32		Certification to the SEC by Dominion Resources, Inc.’s CEO and CFO, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

99		Condensed consolidated earnings statements (unaudited) (filed herewith).

101^		The following financial statements from the Dominion Resources, Inc. Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, filed on July 31, 2009, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) the Notes to Consolidated Financial Statements, tagged as blocks of text.

*	References to filings relate to filings made by Virginia Electric and Power Company, File No. 1-2255.

**	Indicates management contract or compensatory plan or arrangement.

This exhibit will not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 (15 U.S.C. 78r), or otherwise subject to the liability of that section. Such exhibit will not be deemed to be incorporated by reference into any filing under the Securities Act or Securities Exchange Act, except to the extent that the Company specifically incorporates it by reference.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		DOMINION RESOURCES, INC.
		Registrant

July 31, 2009		/s/ Ashwini Sawhney
		Ashwini Sawhney
		Vice President and Controller (Chief Accounting Officer)

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EXHIBIT INDEX


3.1		Articles of Incorporation as in effect August 9, 1999, as amended March 12, 2001 (Exhibit 3.1, Form 10-K for the year ended December 31, 2002, File No. 1-8489, incorporated by reference), as amended November 9, 2007 (Exhibit 3, Form 8-K, filed November 9, 2007, File No. 1-8489, incorporated by reference).

3.2		Amended and Restated Bylaws effective on June 20, 2007 (Exhibit 3.1, Form 8-K filed June 22, 2007, File No. 1-8489, incorporated by reference).

4.1		Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and the Bank of New York (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006, File No. 1-8489, incorporated by reference), as supplemented by the First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006, File No. 1-8489, incorporated by reference); the Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006, File No. 1-8489, incorporated by reference); and the Third Supplemental and Amending Indenture dated as of June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489, incorporated by reference).

4.2		Form of Replacement Capital Covenant entered into by Dominion Resources, Inc. dated as of June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489, incorporated by reference).

4.3		Form of Senior Indenture, dated as of June 1, 1998, between Virginia Electric and Power Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by the First Supplemental Indenture (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255, incorporated by reference); Second Supplemental Indenture (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255, incorporated by reference); Third Supplemental Indenture (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255, incorporated by reference); Form of Fourth Supplemental Indenture (Exhibit 4.2, Form 8-K filed March 26, 2001, File No. 1-2255, incorporated by reference); Form of Fifth Supplemental Indenture (Exhibit 4.3, Form 8-K filed March 26, 2001, File No. 1-2255, incorporated by reference); Form of Sixth Supplemental Indenture (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255, incorporated by reference); Seventh Supplemental Indenture (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255, incorporated by reference); Form of Eighth Supplemental Indenture (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255, incorporated by reference); Form of Ninth Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Tenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Eleventh Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255, incorporated by reference); Form of Twelfth Supplemental Indenture (Exhibit 4.2, Form 8-K filed January 12, 2006, File No. 1-2255, incorporated by reference); Form of Thirteenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed January 12, 2006, File No. 1-2255, incorporated by reference); Form of Fourteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255, incorporated by reference); Form of Fifteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255, incorporated by reference); Form of Sixteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed November 30, 2007, File No. 1-2255, incorporated by reference); Form of Seventeenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed November 30, 2007, File No. 1-2255, incorporated by reference); Form of Eighteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255, incorporated by reference); Nineteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255, incorporated by reference); Form of Twentieth Supplemental Indenture (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255, incorporated by reference).

4.4		Dominion Resources, Inc. agrees to furnish to the SEC upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of its total consolidated assets.

10		Dominion Resources, Inc. 2005 Incentive Compensation Plan, as amended and restated effective May 5, 2009 (Exhibit 10, Form 8-K filed May 11, 2009, File No. 1-8489, incorporated by reference).

PAGE 54



12		Ratio of earnings to fixed charges (filed herewith).

31.1		Certification by Dominion Resources, Inc.’s CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

31.2		Certification by Dominion Resources, Inc.’s CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

32		Certification to the SEC by Dominion Resources, Inc.’s CEO and CFO, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

99		Condensed consolidated earnings statements (unaudited) (filed herewith).

101		The following financial statements from the Dominion Resources, Inc. Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, filed on July 31, 2009, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) the Notes to Consolidated Financial Statements, tagged as blocks of text.

PAGE 55